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

Form 10-Q

(Mark One)

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

For the Quarterly Period Ended June 30, 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 August 9, 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	22
3.	Quantitative and Qualitative Disclosures About Market Risk	64
PART II—Other Information
1.	Legal Proceedings	65
6.	Exhibits and Reports on Form 8-K	67
	Signatures	69

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In thousands)

			Three Months Ended June 30,						Six Months Ended June 30,
			2002			2001			2002			2001
			(Unaudited)						(Unaudited)
Operating Revenues
	Electric revenues		$	679,122		$	582,277		$	1,205,385		$	1,056,279
	Equity in income from energy projects			52,604			104,871			97,638			169,061
	Equity in income from oil and gas investments			3,642			10,063			11,182			30,513
	Net gains from energy trading and price risk management			3,241			14,705			24,607			32,059
	Operation and maintenance services			8,247			11,473			17,781			21,778
		Total operating revenues		746,856			723,389			1,356,593			1,309,690
Operating Expenses
	Fuel			235,193			218,490			448,664			413,681
	Plant operations			212,463			163,746			399,176			304,943
	Plant operating leases			51,266			32,410			103,295			67,806
	Operation and maintenance services			5,913			6,101			13,015			13,542
	Depreciation and amortization			63,074			64,737			122,823			126,094
	Long-term incentive compensation			2,042			823			3,712			(2,891	)
	Administrative and general			41,287			36,299			84,689			72,275
		Total operating expenses		611,238			522,606			1,175,374			995,450
	Operating income			135,618			200,783			181,219			314,240
Other Income (Expense)
	Interest and other income			666			15,003			11,106			26,857
	Gain on sale of assets			—			3,644			—			3,644
	Interest expense			(114,571	)		(140,464	)		(228,578	)		(267,016	)
	Dividends on preferred securities			(5,302	)		(6,090	)		(10,438	)		(12,380	)
		Total other income (expense)		(119,207	)		(127,907	)		(227,910	)		(248,895	)
	Income (loss) from continuing operations before income taxes and minority interest			16,411			72,876			(46,691	)		65,345
	Provision (benefit) for income taxes			5,581			24,976			(27,210	)		27,755
	Minority interest			(10,739	)		(7,009	)		(16,105	)		(7,522	)
Income (Loss) From Continuing Operations				91			40,891			(35,586	)		30,068
	Income (loss) from operations of discontinued foreign subsidiary, net of tax (Note 4)			3,143			(40,607	)		2,981			(21,567	)
Income (Loss) Before Accounting Change				3,234			284			(32,605	)		8,501
	Cumulative effect of change in accounting, net of tax			—			—			—			250
Net Income (Loss)			$	3,234		$	284		$	(32,605	)	$	8,751

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 June 30,						Six Months Ended June 30,
			2002			2001			2002			2001
			(Unaudited)						(Unaudited)
Net Income (Loss)			$	3,234		$	284		$	(32,605	)	$	8,751
Other comprehensive income (expense), net of tax:
	Foreign currency translation adjustments:
		Foreign currency translation adjustments, net of income tax expense (benefit) of $(2,978) and $316 for the three months and $(2,111) and $2,665 for the six months ended June 30, 2002 and 2001, respectively		63,396			(4,644	)		79,255			(101,289	)
	Unrealized gains (losses) on derivatives qualified as cash flow hedges:
		Cumulative effect of change in accounting for derivatives, net of income tax expense (benefit) of $5,562 for the three and six months ended June 30, 2002 and $(110,900) for the six months ended June 30, 2001		6,357			—			6,357			(230,239	)
		Other unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $(3,472) and $86,200 for the three months and $14,929 and $68,800 for the six months ended June 30, 2002 and 2001, respectively		(23,004	)		120,199			15,081			81,488
		Reclassification adjustments included in net income (loss), net of income tax benefit of $1,389 and $2,000 for the three months and $961 and $17,600 for the six months ended June 30, 2002 and 2001, respectively		2,588			2,411			3,294			30,682
Other comprehensive income (expense)				49,337			117,966			103,987			(219,358	)
Comprehensive Income (Loss)			$	52,571		$	118,250		$	71,382		$	(210,607	)

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

2

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands)

			June 30, 2002		December 31, 2001
			(Unaudited)
Assets
Current Assets
	Cash and cash equivalents		$	343,463	$	372,139
	Accounts receivable—trade, net of allowance of $13,321 and $14,603 in 2002 and 2001, respectively			377,162		312,728
	Accounts receivable—affiliates			20,512		234,203
	Assets under energy trading and price risk management			69,727		64,729
	Inventory			187,311		167,406
	Prepaid expenses and other			71,874		83,085
		Total current assets		1,070,049		1,234,290
Investments
	Energy projects			1,619,927		1,799,242
	Oil and gas			20,262		30,698
		Total investments		1,640,189		1,829,940
Property, Plant and Equipment				7,457,608		6,917,980
	Less accumulated depreciation and amortization			845,566		680,417
		Net property, plant and equipment		6,612,042		6,237,563
Other Assets
	Long-term receivables			264,096		264,784
	Goodwill			682,359		631,735
	Deferred financing costs			67,176		84,780
	Long-term assets under energy trading and price risk management			111,490		2,998
	Restricted cash and other			301,696		290,325
		Total other assets		1,426,817		1,274,622
Assets of Discontinued Operations				13,483		153,610
Total Assets			$	10,762,580	$	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)

			June 30, 2002			December 31, 2001
			(Unaudited)
Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable—affiliates		$	12,639		$	11,964
	Accounts payable and accrued liabilities			376,471			423,287
	Liabilities under energy trading and price risk management			31,462			22,381
	Interest payable			90,794			87,308
	Short-term obligations			53,432			168,241
	Current portion of long-term incentive compensation			4,038			6,170
	Current maturities of long-term obligations			177,086			190,295
		Total current liabilities		745,922			909,646
Long-Term Obligations Net of Current Maturities				5,835,832			5,749,460
Long-Term Deferred Liabilities
	Deferred taxes and tax credits			940,277			936,300
	Deferred revenue			466,142			427,485
	Long-term incentive compensation			38,094			39,331
	Long-term liabilities under energy trading and price risk management			154,535			170,506
	Other			249,171			266,742
		Total long-term deferred liabilities		1,848,219			1,840,364
Liabilities of Discontinued Operations				4,069			55,845
Total Liabilities				8,434,042			8,555,315
Minority Interest				406,251			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			122,050			103,950
		Total preferred securities of subsidiaries		272,050			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			2,633,767			2,631,326
	Retained deficit			(849,827	)		(816,968	)
	Accumulated other comprehensive loss			(197,833	)		(301,820	)
Total Shareholder's Equity				1,650,237			1,576,668
Total Liabilities and Shareholder's Equity			$	10,762,580		$	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)

			Six Months Ended June 30,
			2002			2001
			(Unaudited)
Cash Flows From Operating Activities
	Income (loss) from continuing operations, after accounting change, net		$	(35,586	)	$	30,318
	Adjustments to reconcile income (loss) to net cash provided by (used in) operating activities:
		Equity in income from energy projects		(97,638	)		(169,061	)
		Equity in income from oil and gas investments		(11,182	)		(30,513	)
		Distributions from energy projects		155,880			18,757
		Dividends from oil and gas		21,010			40,667
		Depreciation and amortization		122,823			126,094
		Amortization of discount on short-term obligations		—			1,106
		Deferred taxes and tax credits		(51,410	)		3,817
		Gain on sale of assets		—			(3,644	)
		Cumulative effect of change in accounting, net of tax		—			(250	)
	Changes in operating assets and liabilities:
		Decrease in accounts receivable		146,542			2,799
		Increase in inventory		(19,905	)		(51,305	)
		Decrease (increase) in prepaid expenses and other		(14,853	)		22,232
		Decrease in accounts payable and accrued liabilities		(73,089	)		(348,543	)
		Increase in interest payable		2,517			12,297
		Increase (decrease) in long-term incentive compensation		2,204			(8,077	)
		Decrease (increase) in assets under risk management, net		(27,755	)		29,362
	Other operating, net			(75,114	)		(24,603	)
				44,444			(348,547	)
	Operating cash flow from discontinued operations			35,785			(23,585	)
		Net cash provided by (used in) operating activities		80,229			(372,132	)
Cash Flows From Financing Activities
	Borrowings long-term debt and lease swap agreements			197,076			1,761,342
	Payments on long-term debt agreements			(322,969	)		(985,361	)
	Short-term financing, net			(29,661	)		(39,629	)
	Cash dividends to parent			—			(65,000	)
	Funds provided to discontinued operations			—			(21,080	)
	Issuance of preferred securities			—			14,161
				(155,554	)		664,433
	Financing cash flow from discontinued operations			—			(283,043	)
		Net cash provided by (used in) financing activities		(155,554	)		381,390
Cash Flows From Investing Activities
	Investments in and loans to energy projects			(5,358	)		(290,917	)
	Purchase of common stock of acquired companies			—			(83,381	)
	Purchase of power sales agreement			(80,084	)		—
	Capital expenditures			(176,004	)		(106,224	)
	Proceeds from return of capital and loan repayments			83,754			—
	Proceeds from sale of interest in projects			—			110,853
	Proceeds from sale of assets			43,986			—
	Decrease in restricted cash			109,618			12,879
	Investments in other assets			2,164			(6,849	)
	Other, net			(14,282	)		23,188
				(36,206	)		(340,451	)
	Investing cash flow from discontinued operations			—			(7,012	)
		Net cash used in investing activities		(36,206	)		(347,463	)
Effect of exchange rate changes on cash				27,308			(51,217	)
Net decrease in cash and cash equivalents				(84,223	)		(389,422	)
Cash and cash equivalents at beginning of period				434,249			962,865
Cash and cash equivalents at end of period				350,026			573,443
Cash and cash equivalents classified as part of discontinued operations				(6,563	)		(39,536	)
Cash and cash equivalents of continuing operations			$	343,463		$	533,907

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

5

EDISON MISSION ENERGY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 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 six months ended June 30, 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.

Industry Developments

        A number of significant recent developments have adversely affected not only those companies primarily focused on the trading of electricity but also those independent power producers who sell a sizable portion of their generation, not pursuant to long-term contracts, but rather into the wholesale energy market. Often referred to as merchant generators, the financial performance of these companies has been affected by one or more of the following:

•

A decline in the wholesale prices of energy caused, in part, by a substantial addition of new generating capacity, as well as weak growth in near term demand for electricity, creating oversupply in many regions of the United States.



•

The bankruptcy of Enron and the subsequent disclosure of its having engaged in questionable trading strategies.



•

The disclosure by a number of major energy companies of having engaged in wash trading (generally referring to two countervailing trades between the same counterparties at the same time for the same quantity and price), and the subsequent investigation of these activities by the United States Congress and various federal agencies.



•

The deterioration of the credit ratings and stock valuations of a number of the major merchant generators and energy trading companies.



•

The decline of liquidity in the energy markets as a result of tightening credit and increasing concern about the ability of counterparties to perform against longer term obligations.

        As a result, many merchant generators and power trading firms have announced plans to improve their financial position through asset sales, the cancellation or deferral of substantial new development, decreases in capital expenditures, reductions in operating costs and the issuance of equity.

Our Situation

        Because of the 2000-2001 California power crisis, and its indirect effect on us, we began in early 2001 to shift our emphasis from the development and acquisition of projects to focus instead on enhancing the performance of our existing projects and on maintaining credit quality. As a result, during 2001 and early 2002, we completed the sale of several non-strategic project investments, and,

6

during the first quarter of 2002, further reduced business development activities and undertook a related effort to reduce both corporate overhead and other expenditures across the organization and reduce debt.

        Notwithstanding these efforts, we have this year been affected by lower wholesale prices of energy, particularly at our Homer City facilities in Pennsylvania and the diminished ability to enter into forward contracts for the sale of power primarily from these facilities because of the credit constraints affecting us and many of our counterparties.

        Our Illinois Plants have been largely unaffected by these developments this year, because Exelon Generation is under contract to buy substantially all of the capacity of these units for the balance of 2002. However, as permitted by the contracts governing our coal-fired units in Illinois, Exelon has advised us that they will not exercise their right to purchase 2,684 megawatts (MW) of the capacity of these units for 2003 and 2004. As a result, beginning in 2003, the portion of our generation to be sold into the wholesale markets will significantly increase, thereby increasing our merchant risk. See "Management's Discussion and Analysis of Results of Operations and Financial Condition—Market Risks—Illinois Plants."

        In addition, our credit rating and the credit ratings of some of our major subsidiaries are under review for possible downgrade below investment grade by Moody's and Standard & Poor's due to industry developments, lower wholesale energy prices and the increase in our merchant risk beginning in 2003 as described above. See "Management's Discussion and Analysis of Results of Operations and Financial Condition—Credit Ratings."

        Against this background, we have:

•

reduced our already modest proprietary trading activities in Boston and further emphasized our focus on sales of power from, and risk management around, our Homer City facilities and Illinois Plants;



•

suspended new business development activities;



•

initiated a review of our capital expenditure program to determine whether individual projects appropriately can be delayed or cancelled;



•

in connection with the foregoing, undertaken a review of the future plans for the three turbines in fabrication which we have on order;



•

announced that beginning in January 2003 operations will be suspended at Units 1 and 2 of our Will County plant in Illinois; and



•

initiated a company-wide review of our organization and related costs.

        In addition, we continue to review the possibility of sales of assets, but believe that current market conditions may inhibit our ability to obtain prices commensurate with our valuation of those investments which we might wish to offer for sale. For a discussion of our current financial condition, see "Management's Discussion and Analysis of Results of Operations and Financial Condition—Liquidity and Capital Resources."

7

NOTE 2. INVENTORY

        Inventory is stated at the lower of weighted average cost or market. Inventory at June 30, 2002 and December 31, 2001 consisted of the following:

	June 30, 2002		December 31, 2001
	(Unaudited)
	(in millions)
Coal and fuel oil	$	127.7	$	110.1
Spare parts, materials and supplies		59.6		57.3
Total	$	187.3	$	167.4

NOTE 3. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

        Accumulated other comprehensive income (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		79.3			24.7			104.0
Balance at June 30, 2002 (Unaudited)	$	(54.1	)	$	(143.7	)	$	(197.8	)

        Unrealized gains (losses) on cash flow hedges included those related to 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 does not qualify under the normal sales and purchases exception because financial settlement of the contract occurs without physical delivery. Approximately 60% of our accumulated other comprehensive loss at June 30, 2002 related to net unrealized losses on the cash flow hedge resulting from this contract. These losses arise because current forecasts of future electricity prices in these markets are greater than our contract prices. Nevertheless, we believe that these contract prices meet our profit objectives and insulate us from fluctuations in market prices. Assuming the long-term contract with the State Electricity Commission of Victoria continues to qualify for treatment as a cash flow hedge, future changes in the forecast of market prices for the contract volumes included in this contract 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 those related to our share of interest rate swaps of our unconsolidated affiliates and the Loy Yang B project.

        As our hedged positions are realized, approximately $4.8 million, after tax, of the net unrealized losses on cash flow hedges at June 30, 2002 are expected to be reclassified into earnings during the next 12 months. Management expects that when the hedged items are recognized in earnings, the net unrealized losses associated with them will be offset. The maximum period over which we have designated a cash flow hedge, excluding those forecasted transactions related to the payment of variable interest on existing financial instruments, is 14 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.

8

Net proceeds from the sales of £643 million were used to repay borrowings outstanding under the existing debt facility related to the acquisition of the power plants. We recorded an after tax loss during 2001 of $1.1 billion related to the loss on disposal of these assets. 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, "Accounting for the Impairment or Disposal of Long-Lived Assets." 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 June 30,						Six Months Ended June 30,
	2002			2001			2002			2001
	(Unaudited)(in millions)
Total operating revenues	$	(1.0	)	$	92.3		$	(0.4	)	$	276.1
Income (loss) before income taxes		3.1			(64.9	)		3.0			(53.3	)
Income (loss) before accounting change		3.1			(40.6	)		3.0			(27.3	)
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		3.1			(40.6	)		3.0			(21.5	)

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

		June 30, 2002		December 31, 2001
		(Unaudited)
Cash and cash equivalents		$	6.6	$	62.1
Accounts receivable—trade, net of allowance of $1.2 million and $1.4 million in 2002 and 2001, respectively			6.7		88.4
Other current assets			0.2		1.5
	Total current assets		13.5		152.0
Other assets			—		1.6
	Total long-term assets		—		1.6
Assets of discontinued operations		$	13.5	$	153.6
Accounts payable and accrued liabilities		$	4.1	$	51.6
Interest payable			—		4.2
	Total current liabilities		4.1		55.8
Liabilities of discontinued operations		$	4.1	$	55.8

9

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 (in millions):

			June 30, 2002			December 31, 2001
			(Unaudited)
Derivatives:
	Interest rate:
		Interest rate swap/cap agreements	$	(24.6	)	$	(35.8	)
		Interest rate options		(0.2	)		(1.0	)
	Commodity price:
		Forwards		50.5			63.8
		Futures		(0.5	)		(8.4	)
		Options		0.2			0.4
		Swaps		(127.8	)		(137.6	)
	Foreign currency forward exchange agreements			(0.6	)		(0.6	)
	Cross currency interest rate swaps			3.9			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 into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. The following table summarizes the maturities, the valuation method and the related fair value of our risk management assets and liabilities (as of June 30, 2002) (in millions):

	Total Fair Value			Maturity <1 year		Maturity 1 to 3 years		Maturity 4 to 5 years			Maturity >5 years
	(Unaudited)
Assets:
Prices actively quoted	$	26.0		$	23.7	$	2.3	$	—		$	—
Prices based on models and other valuation methods		40.3			14.9		22.4		3.0			—
Total Assets	$	66.3		$	38.6	$	24.7	$	3.0		$	—
Liabilities:
Prices actively quoted	$	10.0		$	7.9	$	2.1	$	—		$	—
Prices based on models and other valuation methods		133.9			10.2		18.3		11.4			94.0
Total Liabilities	$	143.9		$	18.1	$	20.4	$	11.4		$	94.0
Grand Total	$	(77.6	)	$	20.5	$	4.3	$	(8.4	)	$	(94.0	)

        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 Derivative Financial Instruments

        On September 1, 2000, we acquired the trading operations of Citizens Power LLC and, subsequently, combined them with our trading and risk management operations, now conducted by our subsidiary, Edison Mission Marketing & Trading, Inc. As a result of a number of industry and credit

10

related factors, we have minimized our trading activities and our price risk management activities with third parties not related to our power plants or investments in energy projects. See "Management's Discussion and Analysis of Results of Operations and Financial Condition—Industry Developments." To the extent we engage in trading activities, we seek to manage price risk and create stability of future income by selling electricity in the forward markets and, to a lesser degree, 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 purchase contracts and manage our exposure through a value at risk analysis as described further below.

        The fair value of the financial instruments, including forwards, futures, options and swaps, related to trading activities as of June 30, 2002 and December 31, 2001, which include energy commodities, are set forth below (in millions):

	June 30, 2002				December 31, 2001
	Assets		Liabilities		Assets		Liabilities
	(Unaudited)
Forward contracts	$	115.5	$	25.8	$	4.6	$	2.9
Futures contracts		—		0.1		0.1		0.1
Option contracts		0.8		0.2		—		—
Swap agreements		10.5		4.8		0.2		—
Total	$	126.8	$	30.9	$	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. The following table summarizes the maturities, the valuation method and the related fair value of our energy trading assets and liabilities (as of June 30, 2002) (in millions):

	Total Fair Value		Maturity <1 year		Maturity 1 to 3 years		Maturity 4 to 5 years		Maturity >5 years
	(Unaudited)
Assets:
Prices actively quoted	$	13.9	$	13.9	$	—	$	—	$	—
Prices based on models and other valuation methods		115.4		4.3		7.7		10.2		93.2
Total Assets	$	129.3	$	18.2	$	7.7	$	10.2	$	93.2
Liabilities:
Prices actively quoted	$	11.3	$	11.3	$	—	$	—	$	—
Prices based on models and other valuation methods		22.1		6.9		4.3		3.7		7.2
Total Liabilities	$	33.4	$	18.2	$	4.3	$	3.7	$	7.2
Grand Total	$	95.9	$	—	$	3.4	$	6.5	$	86.0

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        The net realized and unrealized gains or losses arising from trading activities for the three and six month periods ended June 30, 2002 and 2001 are as follows (in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
	2002			2001			2002			2001
	(Unaudited)
Operating Revenues
Forward contracts	$	2.6		$	7.2		$	20.2		$	1.6
Futures contracts		(0.4	)		(0.4	)		(0.6	)		(1.9	)
Option contracts		(0.1	)		(0.3	)		(0.5	)		2.9
Swap agreements		4.4			—			3.9			(0.2	)
Total	$	6.5		$	6.5		$	23.0		$	2.4

        The unrealized gain (loss) from trading and price risk management activities included in the above amounts was $(0.1) million for the three month periods ended June 30, 2002 and 2001, and $11.3 million and $(16.9) million for the six month periods ended June 30, 2002 and 2001, respectively.

NOTE 6. COMMITMENTS AND CONTINGENCIES

Capital Expenditures

        The estimated capital expenditures by our subsidiaries for the remainder of 2002 are $98.3 million. We have anticipated that upgrades to environmental controls at the Illinois Plants to reduce nitrogen oxide emissions would result in expenditures of approximately $317.5 million for the period 2003 - 2005. As a result of changes in the merchant energy marketplace, we are evaluating our capital expenditure program, including environmental improvements. At June 30, 2002, we have capitalized $33.5 million as construction in progress related to environmental improvements. We are currently updating our capital expenditure program and evaluating whether to proceed, delay or cancel individual projects. We expect to complete the update of our capital expenditure program by the end of 2002.

        On August 9, 2002, we exercised our option to purchase the Illinois peaker power units that were subject to a lease with a third-party lessor. As disclosed in Off-Balance Sheet Transactions in our 2001 Annual Report on Form 10-K, this operating lease was structured to maintain a minimum amount of equity (3% of the acquisition price) for the duration of the lease term in accordance with existing guidance for leases involving special purpose entities (sometimes referred to as synthetic leases). This transaction represents the only synthetic lease that we had outstanding at June 30, 2002. The exercise of the purchase option resulted in the payment of $300 million to the owner-lessor, of which we received $255 million as repayment of the note receivable held by us. Accordingly, the net cash outlay required to exercise the purchase option was $45 million. See our 2001 Annual Report on Form 10-K for further information on off-balance sheet transactions.

        We have commitments to purchase three turbines from Siemens Westinghouse for a new gas-fired project. These turbines are planned to be used to meet our additional gas-fired generation obligation at the Illinois Plants, or for a new development project. The amount capitalized at June 30, 2002 related to these three turbines was $75.2 million. Due to continued changes in the wholesale energy markets and discussions regarding the additional gas-fired generation obligation at the Illinois Plants (see update under "Additional Gas-Fired Generation" included in this note), we are evaluating whether to consummate the purchase of these turbines and maintain them in storage until market conditions improve or cancel the equipment purchase contracts for these turbines. If we cancel the contracts, under the terms of the purchase contracts, we would be entitled to recover cash amounts paid in excess of 50% of the turbine purchase price, but it would also result in a pre-tax loss of $60.5 million. We expect to make a decision regarding the plan for these turbines by September 30, 2002.

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Commercial Commitments

        The following table summarizes our consolidated commercial commitments as of June 30, 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	$	50.6	$	3.5	$	28.2	$	—	$	—	$	0.5	$	82.8
Firm commitment for asset purchase		38.0		5.0		—		—		—		—		43.0
Firm commitments to contribute project equity		58.8		67.4		—		—		—		—		126.2
Environmental improvements at our project subsidiaries		33.2		—		—		—		—		—		33.2
Total Commercial Commitments	$	180.6	$	75.9	$	28.2	$	—	$	—	$	0.5	$	285.2

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 guarantees 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, counterparties to these contracts could request us to provide adequate assurance. Adequate assurance could take the form of supplying additional financial information, collateral, letters of credit or cash. As of June 30, 2002, the amount of such exposure under counterparty trade agreements was $6.8 million. Failure to provide adequate assurance could result in a counterparty liquidating an open position and filing a claim against us for any losses.

        Our United Kingdom price risk management activities for our First Hydro project are managed through our subsidiary, Edison Mission Marketing and Services Limited. We currently provide guarantees by Edison Mission Energy of most of this subsidiary's grid trade master agreements (referred to as GTMAs) with third-party counterparties in order to support the credit of First Hydro. If we do not maintain an investment grade rating or if other events adversely affect our financial position, counterparties could request us, under the terms of the relevant GTMA, to provide adequate assurance similar to the description above for domestic activities.

        Our trading and price risk management activities have been adversely affected by a number of factors, including the bankruptcy filing of Enron, increased concern regarding the liquidity of independent power companies, decreases in market prices in U.S. wholesale energy markets, and risk factors related to our business. We have minimized our trading activities as a result of these factors. It is not certain that market conditions or risks related to our business will change to allow us 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 and Expansion(i)	4.9 million Euro	$	4.8
Siemens Westinghouse Turbines(ii)	—	$	38.2

(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 are expected to continue through the remainder of 2002, the amount of which will depend on the number of projects that are ultimately developed. The Italian Wind expansion project is a 29 MW wind project under development in Sardinia, Italy, adjacent to an existing Italian Wind project site.

(ii)

We have a commitment to purchase three turbines from Siemens Westinghouse. See "Capital Expenditures."

Firm Commitments to Contribute Project Equity

Project	U.S. Currency
	(in millions)
CBK(i)	$	48.5
Italian Wind Expansion(ii)	$	2.8
Sunrise(iii)	$	74.9

(i)

CBK is a 728 MW hydroelectric power project under construction in the Philippines. At June 30, 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 drawdown 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 Italian Wind expansion project is a 29 MW wind project under development in Sardinia, Italy, adjacent to an existing Italian Wind project site. Our wholly-owned subsidiary owns a 50% interest. Equity is to be contributed through the remainder of 2002. Commercial operation of the project is expected in the fourth quarter of 2002.

(iii)

The Sunrise project, located in Fellows, California, 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 matters related to the power purchase agreement with the California Department of Water Resources. See "—Contingencies—Regulatory Developments Affecting Sunrise Power Company."

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

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 term of the power purchase agreement from 2029 to 2040. The Binding Term Sheet serves as the basis under which PT PLN has paid Paiton Energy beginning January 1, 2002. On June 28, 2002, Paiton Energy and PT PLN concluded negotiations on an amendment to the power purchase agreement that includes the agreed commercial terms in the Binding Term Sheet. The Binding Term Sheet will remain in effect until all conditions for effectiveness of the amendment to the power purchase agreement are completed by both parties, which conditions are required to be completed by December 31, 2002. Previously, PT PLN and Paiton Energy entered into an interim agreement (covering February to December 31, 2000), 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 made all of the payments to Paiton Energy as required under these agreements, which were 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 through May 2002, as well as the restructure settlement payments due for the months of January through June 2002, as required and in accordance with the billing procedures agreed in the Binding Term Sheet and the power purchase agreement. Paiton Energy believes that PT PLN will continue to make payments for electricity under the Binding Term Sheet while the parties work to complete the conditions precedent to the effectiveness of the amendment to the power purchase agreement.

        Our investment in the Paiton project increased to $514.4 million at June 30, 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 to increase substantially 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 does not become effective within 180 days of its signing, the parties would be entitled to revert to the terms and conditions of the original power purchase agreement in order to pursue arbitration in an international forum.

        While the Binding Term Sheet has been approved by the project lenders, Paiton Energy has not yet obtained approval of the amendment to the power purchase agreement by the project lenders.

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Paiton Energy and its lenders have initiated negotiations on a restructuring of the senior debt which takes into account the revised payment terms as agreed in the amendment to the power purchase agreement. 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 our 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 fees, royalty fees, and distributions (if any) from the project. We believe that the outcome of this litigation will not have a material adverse effect on our consolidated financial position or results of operations.

ISAB

        In connection with the financing of the ISAB project, which is located near Siracusa in Sicily, Italy, 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 $36 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 10 of the contractor's 14 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 the four successful claims. Certain additional minor claims of the contractor, together with ISAB Energy's counterclaims for defects and delay liquidated damages, 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 our wholly-owned subsidiary owns 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 requested 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. After hearings and intermediate rulings, on July 23, 2002, the Federal Energy Regulatory Commission dismissed with prejudice the California Public Utilities Commission and California Electricity Oversight Board complaints against Sunrise. The California Public Utilities Commission and

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California Energy Oversight Board have a right of appeal to the federal courts of appeal within 60 days of the date of the order.

        On May 2, 2002, the United States Justice Foundation announced that it had filed a complaint in the Superior Court of the State of California, Los Angeles County, 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 the contracts entered into in 2001, as well as all 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.

        On May 15, 2002, Sunrise was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco, by James M. Millar, "individually, and on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to the California Department of Water Resources, including Sunrise. The lawsuit alleges that the defendants, including Sunrise, engaged in unfair and fraudulent business practices by knowingly taking advantage of a manipulated power market to obtain unfair contract terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the defendants of excessive monies obtained by the defendants. Plaintiffs in several other class action lawsuits pending in Northern California have filed petitions seeking to have the Millar lawsuit consolidated with those lawsuits. The defendants in the Millar lawsuit and other class action suits removed all the lawsuits to the U.S. District Court, Northern District of California and filed a motion to stay all proceedings pending final resolution of the jurisdictional issue. Various plaintiffs have filed pleadings opposing the removal and requesting that the matters be remanded to state court. The motions are still pending. We believe that the outcome of this litigation will not have a material adverse effect on our consolidated financial position or results of operations.

Federal Income Taxes

        We received a notice on August 7, 2002, from the Internal Revenue Service (IRS) asserting deficiencies in federal corporation income taxes for our 1994 to 1996 tax years. We will challenge the deficiencies asserted by the IRS. We believe that we have meritorious defenses to those deficiencies and believe that the ultimate outcome of this matter will not result in a material impact on our consolidated results of operations or financial position.

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 June 30, 2002, if payment were required, would be $223.2 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

17

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 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 Commonwealth Edison, Exelon Generation, and the City of Chicago 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)	36.8 million Euro	$	36.3

(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, specified partner obligations or events of default. Our obligation to contribute contingent equity will not exceed $141 million. As of June 30, 2002, $113 million has been contributed as project equity and $23 million deposited with the loan trustee to provide for further contributions if called for. The figure above represents our remaining unfunded commitments.

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 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 to contribute project equity.

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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)
June 30, 2002
Operating revenues	$	409.3	$	206.6	$	132.8	$	(1.8	)	$	746.9
Operating income (loss)		63.6		77.3		38.0		(43.3	)		135.6
Total assets	$	4,869.9	$	3,468.3	$	2,062.0	$	362.4		$	10,762.6
June 30, 2001
Operating revenues	$	503.3	$	96.9	$	122.8	$	0.4		$	723.4
Operating income (loss)		150.1		45.4		39.5		(34.2	)		200.8
Total assets	$	6,724.0	$	3,115.2	$	4,749.7	$	668.4		$	15,257.3

Six Months Ended	Americas		Asia Pacific		Europe and Middle East		Corporate/ Other			Total
	(Unaudited)(in millions)
June 30, 2002
Operating revenues	$	712.7	$	360.8	$	284.9	$	(1.8	)	$	1,356.6
Operating income (loss)		44.1		132.0		89.4		(84.3	)		181.2
Total assets	$	4,869.9	$	3,468.3	$	2,062.0	$	362.4		$	10,762.6
June 30, 2001
Operating revenues	$	912.0	$	145.7	$	250.7	$	1.3		$	1,309.7
Operating income (loss)		224.9		71.0		80.9		(62.6	)		314.2
Total assets	$	6,724.0	$	3,115.2	$	4,749.7	$	668.4		$	15,257.3

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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 June 30,				Six Months Ended June 30,
	2002		2001		2002		2001
	(Unaudited)(in millions)
Operating revenues	$	172.3	$	418.0	$	280.6	$	794.2
Operating income		53.3		151.2		58.8		231.1
Net income		52.9		151.3		61.3		231.2

        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, in which we own 37 percent.

	Three Months Ended June 30,				Six Months Ended June 30,
	2002		2001		2002		2001
	(Unaudited)(in millions)
Operating revenues	$	51.6	$	85.8	$	108.3	$	198.0
Operating income		21.8		55.7		49.3		142.4
Net income		17.4		31.9		34.9		88.7

NOTE 9. SUPPLEMENTAL STATEMENTS OF CASH FLOWS INFORMATION

		Six Months Ended June 30,
		2002			2001
		(Unaudited)
Cash paid
	Interest (net of amount capitalized)	$	202.2		$	220.5
	Income taxes (receipts)	$	(196.8	)	$	14.8
	Cash payments under plant operating leases	$	191.0		$	54.4
Details of assets acquired
	Fair value of assets acquired	$	—		$	888.2
	Liabilities assumed		—			(801.3	)
	Net cash paid for acquisitions	$	—		$	86.9

NOTE 10. CHANGES IN ACCOUNTING

        In December 2001, the Derivative Implementation Group of the Financial Accounting Standards Board 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 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 agreements qualify as cash flow hedges. Under a cash flow hedge, we record the fair value of the forward sales agreements on our balance sheet and record the effective portion of

20

the cash flow hedge as part of other comprehensive income. The ineffective portion of our cash flow hedges is recorded directly in our income statement. We implemented this interpretation on April 1, 2002. We recorded assets at fair value of $11.9 million, deferred taxes of $5.5 million and a $6.4 million increase to other comprehensive income as the cumulative effect of adoption of this interpretation.

        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. This implementation guidance became effective on April 1, 2002. The adoption of this implementation guidance had no impact on our financial statements.

        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. 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 completed the first step described above for each of the components of our goodwill. The fair value of the reporting units for the Contact Energy and First Hydro operations were in excess of related book value at January 1, 2002. Accordingly, no impairment of the goodwill related to these reporting units will be recorded upon adoption of this standard. We concluded that fair value of the reporting unit related to the Citizens Power acquisition was less than our book value and, accordingly, the goodwill related to this reporting unit is impaired at January 1, 2002. We are in the process of completing the second step of the impairment test described above, which will be completed by December 31, 2002.

        The following table sets forth what net income would have been exclusive of goodwill amortization for the three and six months ended June 30, 2002 and June 30, 2001.

	Three Months Ended June 30,				Six Months Ended June 30,
	2002		2001		2002			2001
	(Unaudited)
Reported net income (loss)	$	3.2	$	0.2	$	(32.6	)	$	8.8
Add back: Goodwill amortization, net of tax		—		2.2		—			4.4
Adjusted net income (loss)	$	3.2	$	2.4	$	(32.6	)	$	13.2

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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. Important factors that could cause differences are set forth under "—Credit Ratings" and "—Market Risk Exposures" below, and under "—Risk Factors" in 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.

The Management's Discussion and Analysis of Results of Operations and Financial Condition of this Form 10-Q discusses material changes in the results of operations, financial condition and other developments of Edison Mission Energy since December 31, 2001, and as compared to the second quarter and six months ended June 30, 2001. This discussion presumes that the reader has read or has access to 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.

General

        We are an independent power producer engaged in the business of 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 June 30, 2002, we owned interests in 28 domestic and 50 international operating power projects with an aggregate generating capacity of 23,905 megawatts (MW), of which our share was 19,095 MW. At that date, one domestic and four international projects, totaling 714 MW of generating capacity, of which our anticipated share will be approximately 357 MW, were in construction. At June 30, 2002, we had consolidated assets of $10.8 billion and total shareholder's equity of $1.7 billion.

Industry Developments

        A number of significant recent developments have adversely affected not only those companies primarily focused on the trading of electricity but also those independent power producers who sell a sizable portion of their generation, not pursuant to long-term contracts, but rather into the wholesale energy market. Often referred to as merchant generators, the financial performance of these companies has been affected by one or more of the following:

•

A decline in the wholesale prices of energy caused, in part, by a substantial addition of new generating capacity, as well as weak growth in near term demand for electricity, creating oversupply in many regions of the United States.



•

The bankruptcy of Enron and the subsequent disclosure of its having engaged in questionable trading strategies.



•

The disclosure by a number of major energy companies of having engaged in wash trading (generally referring to two countervailing trades between the same counterparties at the same time for the same quantity and price), and the subsequent investigation of these activities by the United States Congress and various federal agencies.



•

The deterioration of the credit ratings and stock valuations of a number of the major merchant generators and energy trading companies.

22

•

The decline of liquidity in the energy markets as a result of tightening credit and increasing concern about the ability of counterparties to perform against longer term obligations.

        As a result, many merchant generators and power trading firms have announced plans to improve their financial position through asset sales, the cancellation or deferral of substantial new development, decreases in capital expenditures and reductions in operating costs.

Our Situation

        Because of the 2000-2001 California power crisis, and its indirect effect on us, we began in early 2001 to shift our emphasis from the development and acquisition of projects to focus instead on enhancing the performance of our existing projects and on maintaining credit quality. As a result, during 2001 and early 2002, we completed the sale of several non-strategic project investments, and, during the first quarter of 2002, further reduced our business development activities and undertook a related effort to reduce both corporate overhead and other expenditures across the organization and reduce debt.

        Notwithstanding these efforts, we have this year been affected by lower wholesale prices of energy, particularly at our Homer City facilities in Pennsylvania, and the diminished ability to enter into forward contracts for the sale of power primarily from these facilities because of the credit constraints affecting us and many of our counterparties.

        Our Illinois Plants have been largely unaffected by these developments this year, because Exelon Generation is under contract to buy substantially all of the capacity of these units for the balance of 2002. However, as permitted by the contracts governing our coal-fired units in Illinois, Exelon has advised us that they will not exercise their right to purchase 2,684 MW of the capacity of these units for 2003 and 2004. As a result, beginning in 2003, the portion of our generation to be sold into the wholesale markets will significantly increase, thereby increasing our merchant risk. See "—Market Risks—Illinois Plants."

        In addition, our credit rating and the credit ratings of some of our major subsidiaries are under review for possible downgrade below investment grade by Moody's and Standard & Poor's due to industry developments, lower wholesale energy prices and the increase in our merchant risk beginning in 2003 as described above. See "Management's Discussion and Analysis of Results of Operations and Financial Condition—Credit Ratings."

        Against this background, we have:

•

reduced our already modest proprietary trading activities in Boston and further emphasized our focus on sales of power from, and risk management around, our Homer City facilities and Illinois Plants;



•

suspended new business development activities;



•

initiated a review of our capital expenditure program to determine whether individual projects appropriately can be delayed or cancelled;



•

in connection with the foregoing, undertaken a review of the future plans for the three turbines in fabrication which we have on order;



•

announced that beginning in January 2003 operations will be suspended at Units 1 and 2 of our Will County plant in Illinois; and



•

intiated a company-wide review of our organization and related costs.

        In addition, we continue to review the possibility of further sales of assets, but believe for the reasons discussed in more detail below that current market conditions may inhibit our ability to obtain

23

prices commensurate with our valuation of those investments which we might wish to offer for sale. For a discussion of our current financial condition, see "—Liquidity and Capital Resources."

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 was recorded from the sale of our interests in these projects during the first six months of 2002.

        During the second quarter of 2002, we completed our evaluation of bids submitted by third parties to purchase our interests in the EcoEléctrica and Brooklyn Navy Yard 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. Based on our assessment that the net present value of future cash flows from these projects were higher than purchase prices offered, we have decided to maintain our ownership interests and not sell these projects at this time. We continue to discuss the possible sale of our interest in the Gordonsville project, although there is no assurance that we will be able to do so.

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

			Three Months Ended June 30,								Six Months Ended June 30,
			2002				2001				2002				2001
Projects		Business Segment
			Amount			%(1)	Amount			%(1)	Amount			%(1)	Amount			%(1)
			(Unaudited)
Operating revenues:
	Illinois Plants	Americas	$	277.8		37	$	251.0		35	$	441.6		33	$	426.8		33
	Homer City facilities	Americas		80.5		11		105.7		15		166.0		12		234.2		18
	First Hydro	Europe		75.1		10		65.4		9		158.8		12		133.6		10
	Big 4 projects(2)	Americas		28.0		4		89.2		12		34.6		3		129.4		10
	Four Star(3)	Americas		7.3		1		31.0		4		14.7		1		69.2		5
Operating income:
	Illinois Plants	Americas	$	37.5			$	(15.2	)		$	(20.4	)		$	(82.0	)
	Homer City facilities	Americas		(10.9	)			33.0				(8.5	)			87.8
	First Hydro	Europe		15.2				26.0				39.0				52.7
	Big 4 projects(2)	Americas		28.0				89.2				34.6				129.4
	Four Star(3)	Americas		7.0				30.6				14.1				68.4

(1)

Represents percentage of our consolidated operating revenues of these projects. 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 three and six-month 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 the 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 a specific price risk management activity 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 June 30,				Six Months Ended June 30,
		2002		2001		2002		2001
		(Unaudited)(in millions)
Operating revenues		$	364.1	$	379.7	$	623.0	$	687.2
Net gains from energy trading and price risk management			4.8		13.6		23.0		32.5
Equity in income from investments			40.4		110.0		66.7		192.3
	Total operating revenues		409.3		503.3		712.7		912.0
Fuel and plant operations (including plant operating leases)			307.1		308.0		589.6		596.7
Depreciation and amortization			33.2		40.1		67.4		79.5
Administrative and general			5.4		5.1		11.6		10.9
	Operating income	$	63.6	$	150.1	$	44.1	$	224.9

Operating Revenues

        Operating revenues decreased $15.6 million and $64.2 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods 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 a collapse of the selective catalytic reduction system ductwork 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. As a result of the Unit 3 selective catalytic reduction system ductwork collapse, we reviewed the similar structures on Units 1 and 2 and determined that as a precaution it would be appropriate to install additional reinforcement in these structures. The additional reinforcement extended the duration of planned outages for these units, which had been scheduled to end on June 2, 2002. Unit 1 returned to service on June 28, 2002, and Unit 2 returned to service on June 26, 2002.

        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 $274.3 million and $260.5 million for the three-month periods ended June 30, 2002 and 2001, respectively. This represented 37% and 36% of our consolidated operating revenues in 2002 and 2001, respectively. For the six-month periods ended June 30, 2002 and 2001, our revenues under these power purchase agreements were $435.5 million and $425.2 million, respectively. This represented 32% of our consolidated operating revenues for both of these six-month periods. For more information on these power purchase agreements, including Exelon's notice of the amount of capacity and energy purchases for 2003, see "—Market Risk Exposures—Illinois Plants."

        Due to warmer weather during the summer months, electricity 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.

        Net gains from energy trading activities were $6.5 million for the quarters ended June 30, 2002 and 2001, and $23 million and $2.4 million for the six months ended June 30, 2002 and 2001, respectively. The increase in net gains from trading activities in the six months ended June 30, 2002 of $21 million, compared to the corresponding period in 2001, was primarily a result of completing the restructuring of

26

a power sales agreement with an unaffiliated electric utility during the first quarter of 2002. 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 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 net gains of $1.8 million and $18.8 million for the second quarter and six months ended June 30, 2002, attributable to their fair value 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.

        Total gains and 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 $7.1 million for the second quarter and none and $30.1 million for the six months ended June 30, 2002 and 2001, respectively. The decrease in gains of $8.8 million and $30.1 million from the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods in 2001, were primarily due to realized and unrealized gains in 2001 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 second quarter and six months ended June 30, 2001, we recorded a gain on these gas swaps of $20.6 million and $38.0 million due to a decrease in gas prices. During the second quarter of 2002, we entered into hedge transactions related to the gas price risk of our investment in Four Star for 2002 with realized and unrealized gains totaling $0.6 million for the second quarter and six months ended June 30, 2002. In addition, during the second quarter and six months ended June 30, 2001, we recorded a mark-to-market loss of $13.7 million and $8.2 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 $69.6 million and $125.6 million during the second quarter and six months ended June 30, 2002, respectively, compared to the same prior year periods. The 2002 decrease was primarily a return to levels consistent with prior years following a period of higher revenues from cogeneration projects due to higher energy pricing during the six-month period ended June 30, 2001, as well as higher revenues from oil and gas investments due to higher oil and gas prices in the six-month period ended June 30, 2001.

Operating Expenses

        Fuel and plant operations, including plant operating leases, decreased $0.9 million and $7.1 million for the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. The 2002 decrease in fuel expense of $9.2 million resulted from lower fuel costs at the Homer City facilities due to decreased generation during the second quarter of 2002, when the facilities experienced major unplanned outages at Units 1, 2 and 3, as compared to the same period in 2001. In addition, fuel costs were lower at the Illinois Plants during the second quarter and six months ended June 30, 2002 due to lower fuel costs at the Collins Station as compared to the same period in 2001.

        Partially offsetting the 2002 decrease in fuel expense was an increase in plant operating leases of $18.9 million and $35.5 million during the second quarter and six months ended June 30, 2002, as compared to the corresponding periods 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 half of 2001.

27

        Depreciation and amortization expense decreased $6.9 million and $12.1 million for the second quarter and six months ended June 30, 2002, respectively, compared to the same periods last year. The 2002 decrease resulted from lower depreciation expense at the Homer City facilities due 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 energy trading and price risk management operations in Boston, Massachusetts. For the second quarter and six months ended June 30, 2002, there were no material changes in administrative and general expenses.

Operating Income

        Operating income decreased $86.5 million and $180.8 million during the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. The 2002 decrease was primarily due to an operating loss of $11 million for the second quarter and $8.5 million for the six months ended June 30, 2002 from the Homer City facilities resulting from major unplanned outages at Units 1, 2 and 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 system. We have completed a preliminary investigation of the event, and a more in-depth analysis of the root causes of the event is ongoing to determine the extent to which insurers and/or the contractor will cover the resulting costs of property damage and repair. We may also be entitled to recovery of business interruption losses under one of our insurance programs, but such determination has not been made or quantified at this time.

Illinois Postretirement Benefits Other Than Pensions

        Employees at our Illinois facilities in union-represented positions are covered by collective bargaining agreements that are due to expire December 31, 2005. We are currently discussing with the union-represented employees their employee benefits agreement that expired on June 15, 2002. As described in our 2001 Annual Report on Form 10-K, we have accounted for postretirement benefits obligations on the basis of a substantive plan under Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." A substantive plan means that we are assuming for accounting purposes that we will provide for postretirement benefits to union-represented employees following conclusion of negotiations to replace the current benefits agreement, even though we have no legal obligation to do so. If no postretirement benefits are provided, we would treat this as a plan termination under SFAS No. 106 and record a gain. The negotiations regarding these benefits plans are in progress and we expect to finalize an agreement prior to the end of 2002, although we cannot provide any assurance that these negotiations will be completed on this schedule.

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Asia Pacific

		Three Months Ended June 30,				Six Months Ended June 30,
		2002		2001		2002		2001
		(Unaudited)(in millions)
Operating revenues		$	196.4	$	92.4	$	337.4	$	138.6
Net gains from price risk management			1.3		0.6		0.2		0.1
Equity in income from investments			8.9		3.9		23.2		7.0
	Total operating revenues		206.6		96.9		360.8		145.7
Fuel and plant operations			112.4		43.2		197.7		58.2
Depreciation and amortization			16.9		8.3		31.1		16.5
	Operating income	$	77.3	$	45.4	$	132.0	$	71.0

Operating Revenues

        Operating revenues increased $104.0 million and $198.8 million for the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. The 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 gains from price risk management activities recorded at fair value increased $0.7 million and $0.1 million for the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. The gains 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 $5.0 million and $16.2 million during the second quarter and six months ended June 30, 2002, respectively, compared to the same prior year periods. The 2002 increase is primarily due to an increase in our share of income from the Paiton project of $21.6 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 six months ended June 30, 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 six months ended June 30, 2001. Partially offsetting this increase in 2002 was a decrease in equity in earnings of Contact Energy which was accounted for on the equity method of accounting prior to our acquisition of a controlling interest in the company in June 2001.

Operating Expenses

        Fuel and plant operations increased $69.2 million and $139.5 million for the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. The increase was primarily due to consolidating Contact Energy operating expenses, effective June 1, 2001.

        Depreciation and amortization expense increased $8.6 million and $14.6 million for the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. The increase primarily reflects the consolidation of Contact Energy depreciation and amortization expenses, effective June 1, 2001.

29

Operating Income

        Operating income increased $31.9 million and $61.0 million during the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. The 2002 increase was primarily due to consolidating Contact Energy's results of operations, effective June 1, 2001, increased profitability of our Loy Yang B and Valley Power Peaker projects from higher energy prices, and higher equity in income from the Paiton project discussed above.

Europe and Middle East(1)

		Three Months Ended June 30,					Six Months Ended June 30,
		2002			2001		2002		2001
		(Unaudited)(in millions)
Operating revenues		$	127.0		$	121.7	$	262.8	$	252.3
Net gains (losses) from price risk management			(1.1	)		—		3.2		(1.9	)
Equity in income from investments			6.9			1.1		18.9		0.3
	Total operating revenues		132.8			122.8		284.9		250.7
Fuel and plant operations			85.4			69.5		176.9		145.1
Depreciation and amortization			9.4			13.8		18.6		24.7
	Operating income	$	38.0		$	39.5	$	89.4	$	80.9

(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 $5.3 million and $10.5 million for the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods 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 half 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 into purchase and sales contracts covering greater volumes of power to optimize the timing of generation from First Hydro's pumped storage plants. The First Hydro plant is expected to provide for higher electric revenues during the winter months.

        Net gains (losses) from price risk management activities decreased $1.1 million and increased $5.1 million for the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. The 2002 gains (losses) 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 $5.8 million and $18.6 million during the second quarter and six months ended June 30, 2002, respectively, compared to the same prior year periods. The 2002 increase was due to higher profitability of our interest in the ISAB project resulting from

30

increased generation and settlement of an insurance claim. During the first half of 2001, we recorded losses from this project.

Operating Expenses

        Fuel, including purchased power, and plant operations increased $15.9 million and $31.8 million for the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods 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 decreased $1.5 million and increased $8.5 million during the second quarter and six months ended June 30, 2002, respectively, compared to the same periods of 2001. The 2002 increase was primarily due to equity in income from investments partially offset by a decline in earnings from the First Hydro project as discussed above.

Corporate/Other

		Three Months Ended June 30,						Six Months Ended June 30,
		2002			2001			2002			2001
		(Unaudited)(in millions)
Revenues:
Net gains (losses) from price risk management		$	(1.8	)	$	0.4		$	(1.8	)	$	1.3
Expenses:
Depreciation and amortization			3.6			2.6			5.7			5.4
Long-term incentive compensation			2.0			0.8			3.7			(2.9	)
Administrative and general			35.9			31.2			73.1			61.4
	Operating loss	$	(43.3	)	$	(34.2	)	$	(84.3	)	$	(62.6	)

        Net gains (losses) from price risk management activities recorded at fair value decreased $2.2 million and $3.1 million for the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. The losses 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, which terminated in June 2002.

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        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 and interest earned on deferred payouts. During the second quarter of 2001, an adjustment was made to reflect the decrease in market value of stock equivalent units.

        Administrative and general expenses increased $4.7 million and $11.7 million for the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. The increase for the six months ended June 30, 2002 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 to reduce administrative and general operating costs, including reductions in management and administrative personnel.

        We may be entitled to a refund of property insurance premiums based on loss experience for the policy year June 1, 2001 through May 31, 2002 from a portion of the risk that is re-insured by a captive insurance subsidiary of Edison International. We expect that a determination will be made during the third quarter of 2002.

Other Income (Expense)

        Interest and other income decreased $14.3 million and $15.8 million for the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. The 2002 decrease was primarily due to lower interest income and foreign exchange losses from intercompany loans.

        Interest expense decreased $25.9 million and $38.4 million for the second quarter and six months ended June 30, 2002, respectively, compared to the same prior year periods. 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.

Provision (Benefit) for Income Taxes

        During the six months ended June 30, 2002, we recorded an effective tax provision rate (after deduction of minority interest) of 43% 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 six months of 2001 of 48%. The decrease in the annual effective rate is primarily due to increased earnings from taxable unconsolidated affiliates (and therefore not included in our consolidated tax provision), partially offset by an expected decrease in anticipated income from operations in the United Kingdom.

        We received a notice on August 7, 2002, from the Internal Revenue Service (IRS) asserting deficiencies in federal corporation income taxes for our 1994 to 1996 tax years. We will challenge the deficiencies asserted by the IRS. We believe that we have meritorious defenses to those deficiencies and believe that the ultimate outcome of this matter will not result in a material impact on our consolidated results of operations or financial position.

        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 $3.7 million and $8.6 million for the second quarter and six months ended June 30, 2002, respectively, compared to the same prior year periods. The 2002 increase

32

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 United Kingdom 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. Net proceeds from the sales of £643 million were used to repay borrowings outstanding under the existing debt facility related to the acquisition of the power plants. We recorded an after tax loss during 2001 of $1.1 billion related to the loss on disposal of these assets. In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", the results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in the consolidated financial statements.

        During the second quarter of 2002, we recorded income of $3.1 million from discontinued operations primarily related to an insurance recovery from claims filed prior to the sale of the power plants.

        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.

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.

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        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. In December 2001, the Derivative Implementation Group issued a revised interpretation Issue C15, "Normal Purchases and Sales Exception for Option-Type Contracts and Forward Electricity Contracts in Electricity," which changed the requirements such that the Homer City forward contracts no longer qualify for this exception due to our net settlement procedures with counterparties. Accordingly, effective April 1, 2002, we recorded our Homer City forward contracts as cash flow hedges with the fair value of these contracts recorded as part of assets or liabilities from energy trading and price risk management.



•

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 did not qualify under the normal sales and purchases exception because financial settlement of 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 of approximately $0.5 million and $1.5 million during

34

the second quarter of 2002 and 2001, respectively, and a net gain (loss) of approximately $(0.2) million and $1.6 million for the six-month periods 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 June 30, 2002, we had consolidated cash and cash equivalents of $343.5 million and had available a total of $681.3 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 June 30, 2002, there were no cash advances outstanding under either Tranche and $68.7 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 June 30, 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:

	Six Months Ended June 30,
	2002		2001
	(Unaudited) (in millions)
Continuing operations	$	44.4	$	(348.5	)
Discontinued operations		35.8		(23.6	)
	$	80.2	$	(372.1	)

        The higher operating cash flow from continuing operations in the first half of 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 during 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 the first half of 2002 was also due to the timing of cash payables related to working capital items. Net working capital at June 30, 2002 was $324.1 million compared to $324.6 million at December 31, 2001.

        Cash provided by operating activities from discontinued operations in 2002 reflects the settlement of working capital items from the Ferrybridge and Fiddler's Ferry power plants during the first half of 2002.

Cash Flows From Financing Activities

        Net cash provided by (used in) financing activities:

	Six Months Ended June 30,
	2002			2001
	(Unaudited) (in millions)
Continuing operations	$	(155.5	)	$	664.4
Discontinued operations		—			(283.0	)
	$	(155.5	)	$	381.4

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        Cash used in financing activities from continuing operations during the first half of 2002 consisted of payment of $100 million of senior notes that matured, net payments of $80 million on our $750 million corporate credit facility, $22 million related to debt service payments of one of our subsidiaries, and payments of $86 million from our Coal and Capex facility. In addition, a wholly-owned subsidiary borrowed $84 million under a note purchase agreement in January 2002. For further discussion of the note purchase agreement, see "—Subsidiary Financing Plans." We also received $54 million from a swap agreement with a bank related to lease payments with our Homer City facilities. Cash provided by financing activities from continuing operations during the first half of 2001 consisted of issuances under our corporate credit facilities and $600 million from the issuance of 9.875% senior notes in April 2001, due in 2011. In addition, dividends totaling $65 million were paid to The Mission Group and ultimately to Edison International, our ultimate parent company. As of June 30, 2002, we had recourse debt of $1.9 billion, with an additional $4.2 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 during the first half of 2001 was primarily related to the repayment of a loan from Edison Capital, an affiliate.

Cash Flows From Investing Activities

        Net cash used in investing activities:

	Six Months Ended June 30,
	2002			2001
	(Unaudited) (in millions)
Continuing operations	$	(36.2	)	$	(340.5	)
Discontinued operations		—			(7.0	)
	$	(36.2	)	$	(347.5	)

        Cash used in investing activities from continuing operations during the first half of 2002 included $80.1 million paid for the purchase of a power sales agreement held by a third party. We invested $114.9 million in the first half of 2002 in new plant and equipment principally related to the Valley Power Peaker project in Australia, the Illinois Plants, the Homer City facilities, and payments related to three turbines to Siemens Westinghouse. Also, included in capital expenditures during the first half of 2002 were payments for three turbines purchased under the Edison Mission Energy Master Turbine Lease with funds from restricted cash of $61.1 million, which reduced our restricted cash. In addition, $25 million of restricted cash was used to 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% interests 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 of 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. Restricted cash totaling $53 million was used to meet our lease payment obligations.

        Cash used in investing activities from continuing operations during the first half of 2001 included cash used by us for equity contributions totaling approximately $135 million through June 30, 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

37

payment in full by the end of the first quarter of 2003. Through the first half of 2001, $3.8 million was paid towards the purchase price and $1.5 million in equity contributions for the Italian Wind projects, $20 million was paid for the purchase of the 50% interest in the CBK project and $59.5 million was paid for the purchase of additional shares in Contact Energy. In June 2001, we also completed the sale of a 50% interest in the Sunrise project to Texaco for $84 million. We invested $106 million during the first half of 2001 in new plant equipment principally related to the Homer City facilities and Illinois Plants.

Historical Distributions Received By Edison Mission Energy

        The following table is presented as an aid in understanding the cash flow of Edison Mission Energy and its various subsidiary holding companies which depend on distributions from subsidiaries and affiliates to fund general and administrative costs and interest costs of recourse debt. Distributions for the first six months of each year are not necessarily indicative of annual distributions due to the seasonal fluctuations in our business. Distributions for the prior two calendar years have been included as Exhibit 99.1 to this quarterly report on Form 10-Q.

		Six Months Ended June 30,
		2002		2001
		(Unaudited) (in millions)
Distributions from Consolidated Operating Projects:
	Edison Mission Midwest Holdings (Illinois Plants)	$	—	$	—
	EME Homer City Generation L.P. (Homer City facilities)		—		43.7
	First Hydro Holdings		—		51.6
	Holding companies of other consolidated operating projects		4.3		0.3
Distributions from Non-Consolidated Operating Projects:
	Distributions from Big 4 projects(1)		82.0		—
	Distributions from Four Star Oil and Gas Company		21.0		40.7
	Distributions from other non-consolidated operating projects		29.4		14.3
Total Distributions		$	136.7	$	150.6

(1)

The Big 4 projects are comprised of investments in the Kern River project, Midway-Sunset project, Sycamore project and Watson project. Distributions do not include either capital contributions made during the California energy crisis or the return of the capital subsequently. Distributions reflect the amount received by Edison Mission Energy after debt service payments by Edison Mission Energy Funding Corp.

        Changes in distributions between the six-month periods were due to:

•

Lower market prices for energy and capacity and major unplanned outages at the Homer City facilities during the first half of 2002. See "—Results of Operations—Americas."



•

Lower profitability of the First Hydro project.



•

Current payment during the first half of 2002 of accounts receivable by the Big 4 Projects from Southern California Edison, compared to delayed payment during the first half of 2001 as a result of the California energy crisis.



•

Lower profitability in 2002 of Four Star Oil and Gas Company due to lower natural gas prices.



•

Higher distributions from our partnership interests in other California partnerships.

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Restricted Assets of our Subsidiaries

        Each of our direct or indirect subsidiaries is organized as a legal entity separate and apart from us and our other subsidiaries. Assets of our subsidiaries are not available to satisfy our obligations or the obligations of any of our other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law and the terms of financing arrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to us or to an affiliate of ours. Set forth below is a description of covenants binding our principal subsidiaries that may restrict the ability of those entities to make distributions to Edison Mission Energy directly or indirectly through the other holding companies owned by Edison Mission Energy:

Edison Mission Midwest Holdings (Illinois Plants)

        Edison Mission Midwest Holdings is the borrower under a $1.869 billion credit facility with a group of commercial banks. The funds borrowed under this facility were used to fund the acquisition of the Illinois Plants and provide working capital to such operations. Midwest Generation LLC, a wholly-owned subsidiary of Edison Mission Midwest Holdings and a separate SEC registrant, owns, leases or operates the Illinois Plants. Midwest Generation entered into sale-leaseback transactions for the Collins Station as part of the original acquisition and for the Powerton Station and the Joliet Station in August 2000. In order to make a distribution from Edison Mission Midwest Holdings to Edison Mission Energy, Edison Mission Midwest Holdings and Midwest Generation must be in compliance with the covenants specified in these agreements, including the following financial performance requirements measured on the date of distribution:

1.

At the end of each quarter, the debt service coverage ratio for the prior twelve-month period (taken as a whole) must be greater than 1.75 to 1. The debt service coverage ratio is defined as cash receipts from sales less cash disbursements for operating expenses and required capital expenditures divided by the aggregate of the amounts due under the credit facility and the Collins lease.



2.

The debt service coverage ratio projected for each of the next two twelve-month periods must be greater than 1.75 to 1.



3.

The debt-to-capital ratio must be no greater than 0.60 to 1.



4.

Credit ratings of long-term debt of Edison Mission Midwest Holdings must be investment grade. See "—Credit Ratings" for further discussion regarding the impact of a downgrade on the ability of Edison Mission Midwest Holdings to make distributions to Edison Mission Energy.

        Edison Mission Midwest Holdings must also maintain a debt service coverage ratio for the prior twelve-month period of at least 1.50 to 1 as long as the power purchase agreements with Exelon Generation represent 50% or more of Edison Mission Midwest Holdings' and its subsidiaries' revenues. If the power purchase agreements with Exelon Generation represent less than 50% of Edison Mission Midwest Holdings' and its subsidiaries' revenues, it must maintain a debt service coverage ratio of at least 1.75 to 1. Failure to meet such historical debt service coverage ratio is an event of default under the credit agreement and Collins lease agreements, which, upon a vote by a majority of the lenders to accelerate the due date of the obligations of Edison Mission Midwest Holdings or associated with the Collins lease, may result in an event of default under the Powerton and Joliet leases.

        There are no restrictions on the ability of Midwest Generation to make payments on the outstanding intercompany loans from its affiliate Edison Mission Overseas (which is also a subsidiary of Edison Mission Midwest Holdings) or to make distributions directly to Edison Mission Midwest Holdings.

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        At June 30, 2002, we met the historical financial performance measures. However, as a result of lower wholesale energy prices and the possible downgrade of Edison Mission Midwest Holdings' credit rating, we cannot predict at this time whether we expect to meet the forward looking tests or ratings requirements on distribution dates in the future. If we are unable to meet the forward looking tests or ratings requirements, we would be unable to receive distributions of cash from Edison Mission Midwest Holdings on the next distribution date (October 1, 2002), notwithstanding the projected availability of $138 million of cash for distribution on that date.

EME Homer City Generation L.P.

        EME Homer City Generation L.P. completed a sale-leaseback of the Homer City facilities in December 2001. In order to make a distribution, EME Homer City must be in compliance with the covenants specified in the lease agreements, including the following financial performance requirements measured on the date of distribution:

1.

At the end of each quarter, the senior rent service coverage ratio for the prior twelve-month period (taken as a whole) must be greater than 1.7 to 1. The senior rent service coverage ratio is defined as all income and receipts of EME Homer City less amounts paid for operating expenses, required capital expenditures, taxes and financing fees divided by the aggregate amount of the debt portion of the rent, plus fees, expenses and indemnities due and payable with respect to the lessor's debt service reserve letter of credit.



2.

At the end of each quarter, the equity and debt portions of rent then due and payable must have been paid.



3.

The senior rent service coverage ratio (discussed in item 1 above) projected for each of the following two twelve-month periods must be greater than 1.7 to 1.



4.

No more than two rent default events may have occurred, whether or not cured. A rent default event is defined as the failure to pay the equity portion of the rent within five business days of when it is due.

        At June 30, 2002, we met the above financial performance measures. However, as a result of lower wholesale prices of electricity and the adverse impact of the plant outages during the first half of 2002, we do not expect EME Homer City Generation to have funds available for distributions to us in 2002.

First Hydro Holdings

        A subsidiary of First Hydro Holdings, First Hydro Finance plc, is the borrower of £400 million of Guaranteed Secured Bonds due in 2021. In order to make a distribution, First Hydro Finance must be in compliance with the covenants specified in its bond indenture, including the following financial performance requirement:

•

As determined on June 30 and December 31 of each year, the ratio of net revenues (which is generally the consolidated profit of First Hydro Holdings and its subsidiaries before tax) to interest payable on the Guaranteed Secured Bonds for the prior twelve-month period (taken as a whole) must be greater than 1.2 to 1.

        First Hydro's interest coverage ratio must exceed a minimum default threshold included in the Guaranteed Secured Bonds. When measured for the twelve-month period ended June 30, 2002, First Hydro's interest coverage ratio was above the default threshold but was below the threshold required to permit distributions. 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 also be above the distribution threshold when measured for the twelve-month period ended December 31, 2002.

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Compliance by First Hydro with these and other requirements of its bond financing documents is subject, however, to market conditions for the sale of energy and ancillary services.

Edison Mission Energy Funding Corp. (Big 4 Projects)

        Our subsidiaries, which we refer to as the "Guarantors," that hold our interests in the Big 4 Projects completed a $450 million secured financing in December 1996. Edison Mission Energy Funding Corp., a special purpose Delaware corporation, issued notes ($260 million) and bonds ($190 million), the net proceeds of which were lent to the Guarantors in exchange for a note. The Guarantors have pledged their ownership interests in the Big 4 Projects to Edison Mission Energy Funding as collateral for the note. All distributions receivable by the Guarantors from the Big 4 Projects are deposited into a trust account from which debt service payments are made on the obligations of Edison Mission Energy Funding and from which distributions may be made to us if Edison Mission Energy Funding is in compliance with the terms of the covenants in its financing documents, including the following requirements measured on the date of distribution:

1.

The debt service coverage ratio for the preceding four fiscal quarters is at least 1.25 to 1.



2.

The debt service coverage ratio projected for the succeeding four fiscal quarters is at least 1.25 to 1.

        The debt service coverage ratio is determined by the amount of distributions received by the Guarantors from the Big 4 Projects during the relevant quarter divided by the debt service (principal and interest) on Edison Mission Energy Funding's notes and bonds paid or due in the relevant quarter. At June 30, 2002, there were no restrictions under these covenants on our ability to receive distributions. Although the credit ratings of Edison Mission Energy Funding's notes and bonds were recently subject to a downgrade to below investment grade, this will have no effect on the ability of the Guarantors to make distributions to us.

Other Matters Related to Distributions from Subsidiaries or Affiliates

        Paiton Project—Paiton Energy and PT PLN have completed negotiations on an amendment to the power purchase agreement which incorporates the terms and conditions of the Binding Term Sheet into the power purchase agreement. While the project lenders have approved the Binding Term Sheet, Paiton Energy has yet to obtain approval of the amendment to the power purchase agreement 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 as agreed in the amendment to the power purchase agreement. Distributions from the project will not occur until restructuring of the senior debt has been completed, and in any case, are not likely to commence until at least 2005.

        Loy Yang B Project—During 2001, we began construction of a 300 MW gas-fired peaker plant located adjacent to the Loy Yang B coal-fired power plant site, which we refer to as the Valley Power Peaker project. The peaker units will service peaking demand within the National Energy Market of Eastern Australia and, specifically, within the State of Victoria by selling the output of the peakers directly into the pool and by entering into financial contracts related to pool prices with other power generators and distribution businesses. See "—Market Risk Exposures—Commodity Price Risk—Asia Pacific" for a more detailed description of the pool. We completed the construction of the peaker plant during the first half of 2002. We financed construction of the project in part through an interim financing which we are in the process of replacing with long-term financing. Until the long-term financing is completed, we are not permitted to make cash distributions, which we would otherwise have been able to make, from the Loy Yang B project. We expect that the long-term financing of the project will be completed prior to September 30, 2002.

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        Doga Project—A distribution of approximately $20 million from the Doga Project has been approved by project lenders. We are in discussions with our minority partner on the most efficient means of making a distribution from this project and expect that this will be completed by the end of 2002.

        Lakeland Project—With the introduction of the new electricity trading arrangements and the UK government's so-called Transfer Scheme, the Lakeland power sales agreement and related documents required amendment to be consistent with the procedures under the new trading arrangements and to implement the separation of the supply and distribution businesses of the counterparty to the power sales agreement mandated by the Transfer Scheme. These amendments require lender approval without which no distributions are permitted from the project. We are currently seeking approval of agreed amendments and anticipate that the approval process will be completed no later than October 2002 and that distributions will then be made. As of June 30, 2002, approximately $18 million was otherwise available for distribution.

        ISAB Project—We own a 49% interest in the ISAB project in Italy. The project has recently renewed its insurance coverage which, because of the events of September 11, 2001 and the resulting constraints in the insurance industry, is not compliant with the insurance requirements set out in the facility loan documentation. While we believe the coverage obtained is the maximum available at the current time at reasonable commercial rates, deviations from the specified coverages nevertheless require approval of the lending group. Additionally, our partner in the project wishes to transfer its ownership of certain of the project-related assets to an affiliate company and is seeking lender approval for this. Finally, the project is required to provide the lending group periodically with a long-term forecast which is used to determine the loan life coverage ratio based on, among other things, a set of technical assumptions for the project which must be approved by the technical adviser to the lenders. In part because of the overall group-wide cost analysis being undertaken by us, preparation of the technical assumptions has been delayed beyond its due date, thereby delaying preparation of the forecast and the calculation of the loan life coverage ratio. We do not expect to receive distributions from the project until these issues have been resolved with the project's lending group. It is anticipated that these matters will be resolved by December 31, 2002.

Corporate Financial Ratios

        We and our principal bank lenders use two primary financial 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 activities or cash flow statement data set forth in our Consolidated Statement of Cash Flows. While the ratios included in our corporate credit facilities are designed to 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.

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

Financial Ratio	Covenant	Actual at June 30, 2002	Description
Recourse Debt to Recourse Capital Ratio	Less than or equal to 67.5%	62.4%	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	1.93 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 June 30, 2002, our tangible net worth as determined in accordance with the covenant was $967.8 million, which exceeds the covenant requirement of $614.9 million.

        At June 30, 2002, we met the above financial covenants. The actual interest coverage ratio during 2001 and the twelve months ended June 30, 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 2.06 to 1 for the twelve months ended June 30, 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 June 30, 2002 was 1.93 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 half 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 June 30, 2002 and December 31, 2001 was calculated as follows:

		June 30, 2002			December 31, 2001
		(Unaudited)
		(in millions)
Recourse Debt(1)
	Corporate Credit Facilities	$	76.7		$	203.6
	Senior Notes		1,600.0			1,700.0
	Guarantee of termination value of Powerton/Joliet operating leases		1,442.5			1,431.9
	Coal and Capex Facility		172.0			251.6
	Other		45.5			46.3
	Total Recourse Debt to Edison Mission Energy	$	3,336.7		$	3,633.4
Adjusted Shareholder's Equity(2)		$	2,008.5		$	2,039.0
Recourse Capital(3)		$	5,345.2		$	5,672.4
Recourse Debt to Recourse Capital Ratio			62.4	%		64.1	%

(1)

Recourse debt means senior direct obligations of Edison Mission Energy or obligations related to indebtedness or rental expenses of one of its subsidiaries for which Edison Mission Energy has provided a guarantee.

(2)

Adjusted shareholder's equity is defined as the sum of total shareholder's equity and equity preferred securities, less changes in accumulated other comprehensive gain or loss after December 31, 1999.

(3)

Recourse capital is defined as the sum of adjusted shareholder's equity and recourse debt.

        During the six months ended June 30, 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;



•

final repayment of the $100 million senior notes in June 2002; and



•

payments on the Coal and Capex facility with proceeds from Ferrybridge and Fiddler's Ferry working capital settlements that occurred after the 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 June 30, 2002 and the year ended December 31, 2001:

			June 30, 2002			December 31, 2001
			(Unaudited)
			(in millions)
Funds Flow from Operations:
	Operating Cash Flow(1) from Consolidated Operating Projects(2):
		Illinois Plants	$	284.7		$	201.3
		Homer City		101.8			175.2
		Ferrybridge and Fiddler's Ferry		(57.8	)		(104.5	)
		First Hydro		50.6			45.9
	Other consolidated operating projects			64.7			64.1
	Trading and price risk management			8.8			28.2
	Distributions from non-consolidated Big 4 projects(3)			210.9			128.8
	Distributions from other non-consolidated operating projects			88.8			93.5
	Interest income			6.4			9.0
	Operating expenses			(154.3	)		(143.1	)
		Total funds flow from operations		604.6			498.4
Interest Expense:
	From obligations to unrelated third parties			198.2			188.7
	From notes payable to Midwest Generation			115.1			116.1
		Total interest expense		313.3			304.8
Interest Coverage Ratio				1.93			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 flow from operations during the twelve months ended June 30, 2002, compared to the year ended December 31, 2001, were:

•

Lower market prices for energy and capacity and major unplanned outages at the Homer City facilities.



•

Decline in fuel costs, lower operating expenses, and higher capacity revenues for the Illinois Plants.

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•

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 June 30, 2002. However, since the interest coverage ratio test measures the prior four quarters, this project will still affect the ratio until the quarter ended December 31, 2002.



•

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

        Interest expense increased $8.5 million during the twelve months ended June 30, 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, this 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, Moody's and Standard & Poor's downgraded our senior unsecured credit ratings to "Baa3" from "Baa1" and to "BBB-" from "A-," respectively. On July 3, 2002, Moody's placed under review for possible downgrade our rating (senior unsecured at Baa3), and the ratings of our parent, Mission Energy Holding Company (senior secured at Ba2), and our wholly-owned indirect subsidiaries, Edison Mission Midwest Holdings Co. (bank facility at Baa2) and Midwest Generation, LLC (lessor bonds at Baa2). On July 25, 2002, Standard & Poor's changed its outlook to negative from stable on its "BBB-" corporate credit ratings of Edison Mission Energy, Edison Mission Midwest Holdings Co., and Edison Mission Marketing and Trading. In addition, Standard & Poor's changed its outlook to negative from stable on its "BBB-" ratings on the lessor bonds of the Homer City lease and the lessor bonds of the Powerton and Joliet leases. On August 7, 2002, Standard & Poor's lowered its senior unsecured credit rating on Edison Mission Energy Funding Corp. to "BB" from "BBB-." There is no assurance that Moody's and Standard & Poor's will not downgrade these credit ratings below investment grade.

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        If the credit rating of Edison Mission Energy is downgraded below investment grade, Edison Mission Energy 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 ($6.8 million at June 30, 2002); and



•

post a letter of credit or cash collateral to support our $48.5 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 drawdown of the debt facility currently scheduled for late 2002.

        More generally, a downgrade of Edison Mission Energy's credit ratings below investment grade could increase our cost of capital, increase our credit support obligations, affect our ability to meet debt service coverage and other financial ratios specified in various financing agreements binding on us and our subsidiaries, 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 Illinois Plants, 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. Finally, changes in forward market prices and margining requirements could further increase the need for credit support for our trading and risk management activities.

Possible Downgrade of Edison Mission Midwest Holdings

        In the event of a downgrade of Edison Mission Midwest Holdings below investment grade, provisions in the agreements binding on Edison Mission Midwest Holdings and Midwest Generation would limit the ability of Edison Mission Midwest Holdings to use excess cash flow to make distributions to us. The following table summarizes the provisions restricting cash distributions (sometimes referred to as cash traps) and the related changes in the cost of borrowing by Edison Mission Midwest Holdings under the applicable financing agreements:

S&P Rating	Moody's Rating	Cost of Borrowing Margin	Cash Trap
		(based on LIBOR)
BBB- or higher	Baa3 or higher	150	No cash trap
BB+	Ba1	225	50% free cash trapped until six month debt service reserve is funded
BB	Ba2	275	100% of free cash trapped
BB-	Ba3	325	100% of free cash trapped
B+	B1	325	100% cash sweep by lenders to repay debt (excess free cash required to be used to repay debt)

        As part of the sale-leaseback of the Powerton and Joliet power stations, Midwest Generation loaned the proceeds ($1,367 million) to Edison Mission Energy in exchange for promissory notes in the same aggregate amount. Debt service payments by Edison Mission Energy on the promissory notes are used by Midwest Generation to meet its payment obligations under these leases. Furthermore, Edison Mission Energy has guaranteed the lease obligations of Midwest Generation under these leases. Edison Mission Energy's obligations under the promissory notes payable to Midwest Generation are general obligations of Edison Mission Energy and are not contingent upon receiving distributions from Edison Mission Midwest Holdings. See "—Historical Distributions Received by Edison Mission Energy—Edison Mission Midwest Holdings (Illinois Plants)" for a discussion of implications for the Powerton and Joliet leases.

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Possible Downgrade of Edison Mission Marketing & Trading

        Pursuant to the Homer City sale-leaseback documents, a downgrade of Edison Mission Marketing & Trading to below investment grade would restrict the ability of EME Homer City Generation to sell forward the output of the Homer City facilities. Under the sale-leaseback documents, EME Homer City Generation may only engage in permitted trading activities as defined in the documents. These documents include a requirement that the counterparty to such transactions, and EME Homer City Generation, if acting as seller to an unaffiliated third party, be investment grade. We currently sell all of the output from the Homer City facilities through Edison Mission Marketing & Trading, and EME Homer City Generation is not rated. Therefore, in order for us to continue to sell forward the output of the Homer City facilities in the event of a downgrade in Edison Mission Marketing & Trading's credit, either: (1) we must obtain a waiver from the sale-leaseback owner participant to permit EME Homer City Generation to sell directly into the market or through Edison Mission Marketing & Trading; or (2) Edison Mission Marketing & Trading must provide assurances of performance consistent with the investment grade requirements of the sale-leaseback documents. We are permitted to sell the output of the Homer City facilities into the Pennsylvania-New Jersey-Maryland Power Pool (PJM) at any time. See "—Market Risks—Homer City Facilities."

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 June 30, 2002, we had borrowing capacity under this facility of $681.3 million and corporate cash and cash equivalents of $31.4 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. During the first quarter of 2002, cash flow included 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 received $211 million in tax-allocation payments from our ultimate parent company, which included $73 million related to the amount due at December 31, 2001 and $138 million as an estimated tax-allocation payment for 2002. We expect to receive approximately $146 million in tax-allocation payments during the remainder of 2002. Furthermore, we expect to receive tax-allocation payments during 2003 of approximately $200 million. These and cash distributions from our subsidiaries represent the major source of cash of Edison Mission Energy to meet its cash requirements. 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. Also see "—Historical Distributions Received by Edison Mission Energy—Restricted Assets of Subsidiaries." In addition, the timing and amount of tax-allocation payments are dependent on the consolidated taxable income of Edison International and its subsidiaries. See "Intercompany Tax-Allocation Payments."

        In addition, we plan to seek a new $300 million to $400 million corporate facility with financial institutions by September 17, 2002, as a replacement of Tranche A of our existing corporate facility. We understand that a number of merchant energy companies have recently been in discussions with their lenders regarding new credit facilities or extensions to their existing lines of credit. We also understand that, as a result of market conditions surrounding these companies, they have been either unable to renew, extend or otherwise enter into similar credit facilities or have entered into new or amended credit facilities with a reduced size, increased cost of borrowing and more restrictive terms. Accordingly, there is no assurance that we will be able to enter into a new line of credit or, if we are able to enter into a new or extended line of credit, that the amount and the terms would not be

48

substantially different from those under our current credit facility. Tranche B of our corporate facility ($211.7 million) does not expire until September 17, 2004.

Subsidiary Financing Plans

        The estimated capital and construction expenditures of our subsidiaries for the remaining two quarters of 2002 are $98.3 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 $23.3 million in 2002 to fund the estimated capital expenditures of this project, of which $13.2 million was contributed during the first half of 2002. See "—Note 6. Commitments and Contingencies."

        On August 9, 2002, we exercised our option to purchase the Illinois peaker power units that were subject to a lease with a third-party lessor. As disclosed in "Off-Balance Sheet Transactions" in our 2001 Annual Report on Form 10-K, this lease was structured to maintain a minimum amount of equity (3% of the acquisition price) for the duration of the lease term in accordance with existing guidance for leases involving special purpose entities (sometimes referred to as synthetic leases). This transaction represents the only synthetic lease that we had outstanding at June 30, 2002. The exercise of the purchase option resulted in the payment of $300 million to the owner-lessor, of which we received $255 million as repayment of the note receivable held by us. Accordingly, the net cash outlay required to exercise the purchase option was $45 million. The purchase of these peaker units will be recorded as an asset and depreciated over their estimated useful life.

Valley Power Peaker Project

        During 2001, we began construction of a 300 MW gas-fired peaker plant located adjacent to the Loy Yang B coal-fired power plant site in Australia, which we refer to as the Valley Power Peaker project. We own a 60% interest in the Valley Power Peaker project, with the remaining interest held by our 51.2% affiliate, Contact Energy. The peaker units will service peaking demand within the National Energy Market of Eastern Australia and, specifically, within the State of Victoria by selling the output of the peakers directly into the pool and by entering into financial contracts related to pool prices with other power generators and distribution businesses. We completed the construction of the peaker plant during the first half of 2002. We financed construction of this project in part through an interim financing which we are in the process of replacing with long-term financing. Until the long-term financing is completed, we are not permitted to make cash distributions, which we would otherwise be able to make, from the Loy Yang B project. We expect that the long-term financing of the project will be completed prior to September 30, 2002.

Sunrise Project Financing

        We own a 50% interest in Sunrise Power Company, which owns a natural gas-fired facility currently under construction in Kern County, California, which we refer to as the Sunrise project. The Sunrise project consists of two phases. Phase I, a simple-cycle gas-fired facility (320 MW), was completed on June 27, 2001. Phase II, conversion to a combined-cycle gas-fired facility (560 MW), is currently scheduled to be completed in July 2003. Sunrise Power entered into a long-term power purchase agreement with the California Department of Water Resources on June 25, 2001. For further discussion related to this agreement, see "Part II, Item 1. Legal Proceedings—Sunrise Regulatory Proceedings." The construction of the Sunrise project has been funded with equity contributions by its partners, including us. Sunrise Power has engaged a financial advisor to assist with obtaining project financing. In order to obtain project financing, a number of uncertainties need to be resolved related to the power purchase agreement, the credit of the Department of Water Resources and certain

49

environmental permits. If these uncertainties are resolved, we believe that project financing can be obtained in 2003 which would result in a return of a portion of our equity contribution.

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 note purchase agreement to finance the purchase of the power sales agreement held by a third party, make a deposit under a note purchase agreement, and pay for transaction costs. The note is non-recourse to Edison Mission Energy. Debt service is funded and secured by payments from the power sales agreement. The interest rate under the note purchase agreement is fixed at 7.31% and is due in June 2015. Principal payments under the note purchase 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 other subsidiaries of Edison International. We have historically received tax-allocation payments related to domestic net operating losses incurred by us. The amount and timing of tax-allocation payments are dependent, in part, on the consolidated taxable income of Edison International and its subsidiaries and other factors, including specific procedures regarding allocation of state taxes. 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. This occurred in 2002, and, accordingly, we received $211 million in tax-allocation payments from Edison International, which included $73 million related to the amount due December 31, 2001 and $138 million as an estimated tax-allocation payment for 2002. We expect to receive approximately $146 million in tax-allocation payments during the remainder of 2002.

Market Risk Exposures

        Our primary market risk exposures are associated with the sale of electricity from our uncontracted generating plants and the procurement of fuel for them and, therefore, risks arise from fluctuations in electricity and fuel prices, emission and transmission rights interest rates and foreign currency exchange rates. We manage these risks in part by using derivative financial instruments in accordance with established policies and procedures. See "Industry Developments" and "Credit Ratings" for a discussion of the market developments and their impact on our credit and the credit of our counterparties.

Commodity Price Risk

        Our energy trading activities and merchant power plants expose us to commodity price risks. 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.

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        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). As discussed further below, beginning in 2003, we will also be selling a significant portion of our Illinois Plants into wholesale energy markets. In order to provide more predictable earnings and cash flow, we may hedge a portion of the electric output of our merchant plants, the output of which is not committed to be sold under long-term contracts. 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 and emission credits 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 cost of emission credits or allowances;



•

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



•

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



•

the rate of 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

Illinois Plants

        Electric power generated at the Illinois Plants is currently sold under three power purchase agreements with Exelon Generation Company, under 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 revenue for fixed charges, and the energy payments compensate the Illinois Plants for variable costs of production.

        Virtually all of our energy and capacity sales from the Illinois Plants in the first six months of 2002 were to Exelon Generation under the power purchase agreements, and we expect this to continue during the remainder of 2002. Under each of the power purchase agreements, Exelon Generation, upon notice by a given date, has the option in effect to terminate each agreement with respect to all or a portion of the units subject to it.

        Under the power purchase agreement related to our coal-fired generation units, Exelon Generation had the option, exercisable not later than 180 days prior to January 1, 2003, to retain under

51

the terms of the agreement for 2003 the capacity of certain option coal units having a capacity of 3,949 MW, with any such capacity not retained being released after January 1, 2003 from the terms of the agreement. Exelon Generation continues to have a similar option, exercisable not later than 180 days prior to January 1, 2004, to retain or release for 2004 all or a portion of the option coal units retained for 2003. It remains committed to purchase the capacity of certain committed units having 1,696 MW of capacity for both 2003 and 2004.

        In July 2002, Exelon Generation notified Midwest Generation of its exercise of its option to purchase 1,265 MW of capacity and energy during 2003 (of a possible total of 3,949 MW subject to option) from the option coal units. As a result, 2,684 MW of capacity of the Will County 1 and 2, Joliet 6 and 7, and Powerton 5 and 6 units will no longer be subject to the power purchase agreement after January 1, 2003. The notification received from Exelon Generation has no effect on its commitments to purchase capacity from these units for the balance of 2002.

        The following table lists the committed coal units, the units for which Exelon Generation has exercised its call option for 2003, and the units which, as of January 1, 2003, will be released from the terms of the power purchase agreement, along with related pricing information set forth in the power purchase agreement.

Coal-Fired Units

			Summer(1) Capacity Charge ($ per MW Month)			Non-Summer(1) Capacity Charge ($ per MW Month)			Energy Prices ($/MWhr)
Unit Name		Unit Size (MW)
			2003		2002	2003		2002	2003		2002
Committed Units
	Waukegan Unit 7	328	11,000		12,000	1,375		1,500	17.0		16.0
	Crawford Unit 8	326	11,000		12,000	1,375		1,500	17.0		16.0
	Will County Unit 4	520	11,000		12,000	1,375		1,500	17.0		16.0
	Joliet Unit 8	522	11,000		12,000	1,375		1,500	17.0		16.0
		1,696
Option Units(2)
	Waukegan Unit 6	100	21,300		15,520	2,663		1,940	20.0		19.0
	Waukegan Unit 8	361	21,300		15,520	2,663		1,940	20.0		16.0
	Fisk Unit 19	326	21,300		15,520	2,663		1,940	20.0		19.0
	Crawford Unit 7	216	21,300		15,520	2,663		1,940	20.0		19.0
	Will County Unit 3	262	21,300		15,520	2,663		1,940	20.0		16.0
		1,265
Released Units(3)
	Will County Unit 1	156	(3	)	15,520	(3	)	1,940	(3	)	16.0
	Will County Unit 2	154	(3	)	15,520	(3	)	1,940	(3	)	19.0
	Joliet Unit 6	314	(3	)	15,520	(3	)	1,940	(3	)	19.0
	Joliet Unit 7	522	(3	)	15,520	(3	)	1,940	(3	)	19.0
	Powerton Unit 5	769	(3	)	15,520	(3	)	1,940	(3	)	16.0
	Powerton Unit 6	769	(3	)	15,520	(3	)	1,940	(3	)	16.0
		2,684
		5,645

(1)

"Summer" months are June, July, August and September, and "Non-Summer" months are the remaining months in the year.

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(2)

Option units refer to those option units for which Exelon Generation has exercised its right to purchase capacity and energy during 2003 under the terms of the power purchase agreement.

(3)

Released units refer to those option units for which Exelon Generation has not exercised its right to purchase capacity and energy during 2003, and which are thus released from the terms of the power purchase agreement. After January 1, 2003, the price for energy and capacity from these units will be based upon either the terms of new bilateral contracts or prices received from forward and spot market sales.

        Exelon Generation also has the option, which it may exercise on or before October 2, 2002, to terminate the power purchase agreements related to the Collins Station and the peaker plants effective as of January 1, 2003. We are unable to predict whether Exelon will exercise this option as to any of the Collins or peaker units. The exercise of these options will have no effect on Exelon's commitments to purchase capacity from these units for the remainder of 2002.

        In July 2002, Midwest Generation and Exelon Generation amended the power purchase agreement related to our peaker plants to reinstate, as of July 1, 2002, within the terms of that agreement four of the oil peaker units at our Fisk Station with a capacity of 160 MW. These units had been released from the terms of that agreement by Exelon Generation's previous exercise of its options.

        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 through a combination of bilateral agreements, forward energy sales and spot market sales. Thus, we will be subject to the market risks related to the price of energy and capacity described above. We intend to manage this risk, in part, by accessing both the direct customer and over-the-counter markets described below as well as using derivative financial instruments in accordance with established policies and procedures.

        During 2003, the primary markets available to us for electricity sales from the Illinois Plants are expected to be "direct customer" and "over-the-counter." Direct customer transactions are bilateral sales to regional buyers that principally include investor-owned utilities, municipal utilities, rural electric cooperatives and retail energy suppliers. Transactions in the direct customer market include real-time, daily and longer term structured sales that meet the specific requirements of wholesale electricity consumers. Over-the-counter markets are generally accessed through third-party brokers and electronic exchanges, and include forward sales of electricity. The most liquid over-the-counter markets in the Midwest region are "Into Cinergy," and, to a lesser extent, "Into ComEd."

        "Into Cinergy" and "Into ComEd" are bilateral markets for the sale or purchase of electrical energy for future delivery. The emergence of "Into Cinergy," and "Into ComEd" as commercial hubs for the trading of physical power has not only facilitated transparency of wholesale power prices in the Midwest, but also aided in the development of risk management strategies that are utilized to mitigate commodity price volatility. Energy is traded in the form of physical delivery of megawatt-hours. Delivery is either made (1) into the receiving control area's transmission system (i.e., Cinergy's or ComEd's transmission system) by the seller's daily election of control area interface, or (2) by procuring energy generated from a source within the receiving control area. Almost all of the Illinois Plants have busbar delivery that meets the "Into ComEd" delivery criteria. Performance of transactions in these markets is secured by liquidated damages and, in the case of less creditworthy counterparties, credit support provisions such as letters of credit and cash margining arrangements.

        The following table sets forth the forward month-end market prices for energy per megawatt hour for the calendar 2003 and calendar 2004 "strips" (defined as energy purchases for the entire calendar year) as publicly quoted for sales "Into ComEd" and "Into Cinergy" during the first six months of 2002. As indicated above, these forward prices will continue to fluctuate as a result of a number of factors, including gas prices, electricity demand, which is also affected by economic growth, and the

53

amount of existing and planned power plant capacity. The actual spot prices for electricity delivered into these markets may vary materially from the forward market prices.

Into ComEd*

	2003						2004
Date
	On-Peak		Off-Peak		24-Hr		On-Peak		Off-Peak		24-Hr
January 31, 2002	$	27.26	$	18.34	$	22.56	$	28.72	$	19.09	$	23.65
February 28, 2002		28.96		18.50		23.48		31.30		19.25		24.99
March 31, 2002		32.50		19.85		25.56		34.31		21.35		27.20
April 30, 2002		32.55		19.05		25.65		33.55		20.05		26.65
May 31, 2002		30.85		17.31		23.71		32.30		19.18		25.38
June 30, 2002		29.54		16.88		22.50		30.98		19.38		24.53

Into Cinergy**

	2003						2004
Date
	On-Peak		Off-Peak		24-Hr		On-Peak		Off-Peak		24-Hr
January 31, 2002	$	28.38	$	18.77	$	23.32	$	29.85	$	19.52	$	24.41
February 28, 2002		30.30		18.75		24.25		32.64		19.50		25.75
March 31, 2002		33.82		20.15		26.33		35.63		21.65		27.97
April 30, 2002		34.03		19.75		26.73		35.03		20.75		27.73
May 31, 2002		31.74		18.88		24.96		33.97		20.75		27.00
June 30, 2002		31.08		18.25		23.95		32.50		20.75		25.97

(1)

On-peak refers to the hours of the day between 7:00 a.m. and 11:00 p.m. Monday through Friday. All other hours of the week are referred to as off-peak.

*

Source: Prices were obtained by gathering publicly available broker quotes adjusted for historical basis differences between ComEd and Cinergy.

**

Source: Prices were obtained by gathering publicly available broker quotes.

        Midwest Generation intends to hedge a portion of its merchant portfolio risk. To the extent it does not do so, the unhedged portion will be subject to the risks and benefits of spot-market price movements. The extent to which Midwest Generation will hedge its market price risk through forward over-the-counter sales depends on several factors. First, Midwest Generation will evaluate over-the-counter market prices to determine whether sales at forward market prices are sufficiently attractive compared to assuming the risk associated with spot market sales. Second, Midwest Generation's ability to enter into hedging transactions will depend upon Midwest Generation's liquidity and upon the over-the-counter forward sales markets' having sufficient liquidity to enable Midwest Generation to identify counterparties who are able and willing to enter into hedging transactions with Midwest Generation. Due to factors beyond Midwest Generation's control, market liquidity has decreased significantly since the beginning of 2002, and a number of formerly significant trading parties have completely withdrawn from the market or substantially reduced their trading activities. This decrease in market liquidity may require Midwest Generation to rely more heavily on sales to end user counterparties in the direct customer markets. Midwest Generation is unable to predict the credit quality that such end user counterparties may have. In the event a counterparty were to default on its trade obligation, Midwest Generation would be exposed to the risk of possible loss associated with reselling the contracted product at a lower price if the non-performing counterparty were unable to pay the resulting liquidated damages owed to Midwest Generation. Further, Midwest Generation would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time such counterparty defaulted.

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        In addition to the prevailing market prices, the ability of Midwest Generation to derive profits from the sale of electricity from the released units will be affected by the cost of production, including costs incurred to comply with environmental regulations. The costs of production of the released units vary and, accordingly, depending on market conditions, the amount of generation that will be sold from the released units is expected to vary from unit to unit. In this regard, we have announced a plan to suspend operations of Units 1 and 2 at our Will County plant at the end of 2002 until market conditions improve. If market conditions were to be depressed for an extended period of time, we would need to consider decommissioning these units, which would result in a charge against income.

        Midwest Generation's ability to transmit energy to counterparty delivery points to consummate spot sales and hedging transactions may be affected by transmission constraints. Although the Federal Energy Regulatory Commission (FERC) and the relevant industry participants are working to minimize such issues, Midwest Generation cannot predict how quickly or how effectively such issues will be resolved.

        A group of transmission-owning utilities have asked the FERC to permit them to join PJM, and the FERC granted those requests, with conditions, in an order issued on July 31, 2002. These companies include Commonwealth Edison and American Electric Power. As recently filed by Commonwealth Edison with FERC, Commonwealth Edison will join PJM either as an individual transmission owner, or as a member of an Independent Transmission Company (ITC). Furthermore, as filed by Commonwealth Edison and approved by FERC, the Commonwealth Edison transmission system, to which the Illinois Plants are directly interconnected, will be fully integrated into the PJM market structure by the last quarter of 2003. We believe that the integration into the PJM market will allow us to sell electricity into a well developed, stable, transparent, and liquid cash market without additional transmission charges. The expanded PJM market will be interconnected by numerous extra-high voltage transmission ties and will include (in addition to the existing market encompassed by PJM) the service territories of Commonwealth Edison, American Electric Power, Illinois Power, Virginia Power, and Dayton Power and Light. Furthermore, as a condition of approval of the requests to join PJM, the FERC is requiring PJM and its counterpart transmission entity in the Midwest to form a common, seamless energy market by October 2004, which would further expand the areas into which we may sell power without incurring multiple transmission charges.

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 are situated in the PJM control area and are 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.

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        The following table depicts the average historical market prices per megawatt hour in PJM during the first six months of 2002 and 2001:

	24-Hour PJM Historical Prices*
	2002		2001
January	$	20.52	$	36.66
February		20.62		29.53
March		24.27		35.05
April		25.68		34.58
May		21.98		28.64
June		24.98		26.61
Six-month Average	$	23.01	$	31.85

*

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

        As shown on the above table, the average historical market prices during the first six months of 2002 are below the average market prices during the first six months of 2001. These forward prices will continue to 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. The actual spot prices for electricity delivered into these markets may vary materially from the forward market prices. At the end of July 2002, our forecasted yearly average 24-hour PJM price for 2002 was $25.31, compared to the actual yearly average 24-hour PJM price 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 following table sets forth the forward month-end market prices for energy per megawatt hour for the calendar 2003 and calendar 2004 "strips" (defined as energy purchases for the entire calendar year) for sales in PJM during the first six months of 2002.

	24-Hour PJM Forward Prices*
	2003		2004
January 31, 2002	$	25.48	$	26.31
February 28, 2002		27.11		27.59
March 31, 2002		29.69		29.66
April 30, 2002		29.19		28.81
May 31, 2002		28.40		28.24
June 30, 2002		27.96		28.09

*

Prices were obtained by gathering publicly available broker quotes.

        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, depends on revenues generated by the Homer City facilities, which depend in part on the market conditions for the sale of capacity and energy. These market conditions are beyond our control.

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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 (effective July 2, 2002, this time period became 1 hour) 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 were adversely affected 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 was 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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        Despite the foregoing, First Hydro's interest coverage ratio, when measured for the twelve-month period ended June 30, 2002, was above the default threshold in its bond financing documents, and it was able to make the July 31, 2002 interest payment 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 also be above the default and distribution thresholds 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.

Asia Pacific

        Australia.    The Loy Yang B plant and the Valley Power Peaker project sell 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 and the Valley Power Peaker project have 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 Loy Yang B plant output sold is hedged under the State Hedge. From August 2014 to October 2016, approximately 56% of the Loy Yang B plant output sold is hedged under the State Hedge. Additionally, the Loy Yang B plant and the Valley Power Peaker project have 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 and/or cap contracts that expire on various dates through 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 of varying terms that expire on various dates through March 31, 2007 and option contracts of varying terms that expire on various dates through October 31, 2002. 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 developed, 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. A draft single governance code was put forward to the New Zealand Commerce Commission for approval early in 2002. In May 2002, the Commerce Commission passed the draft back to the industry requiring a number of amendments to be made prior to the Commerce Commission giving its approval. Negotiations between the industry and the Commerce Commission over these amendments are continuing. The new code is likely to be introduced before the end of 2002.

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Credit Risks

        In conducting our trading and price risk management activities, we contract with a number of utilities, energy companies and financial institutions. To manage credit risk, we look at the risk of a potential default by our counterparties. Credit risk is measured by the loss we would record if our counterparties failed to perform pursuant to the terms of their contractual obligations. We have established controls to determine and monitor the creditworthiness of counterparties and use master netting agreements whenever possible to mitigate our exposure to counterparty risk. We may require counterparties to pledge collateral when deemed necessary. We try to manage the credit in the portfolio based on credit ratings. We use published ratings of counterparties to guide us in the process of setting credit levels, risk limits and contractual arrangements including master netting agreements. Where external ratings are not available, we conduct internal assessments of credit risks of counterparties. The credit quality of our counterparties is reviewed regularly by our risk management committee. We also monitor the concentration of credit risk from various positions, including contractual commitments. Credit concentration is determined on both an individual and group counterparty basis. In addition to continuously monitoring our credit exposure to our counterparties, we also take appropriate steps to limit exposures, initiate actions to lower credit exposure and take credit reserves if appropriate.

        Exelon Generation accounted for 36% and 42% of our consolidated operating revenues in 2001 and 2000, respectively. We expect Exelon Generation to represent a similar amount of our consolidated revenues in 2002. Any failure of Exelon Generation to make payments under the power purchase agreements could adversely affect our results of operations and financial condition.

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 $19.6 million and $8.4 million of additional interest expense for the six months ended June 30, 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 $53.4 million at June 30, 2002, consisting of borrowings under a construction facility for the Valley Power Peaker project and a floating rate loan related to Contact Energy. The fair values of these obligations approximated their carrying values at June 30, 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 $6.0 billion at June 30, 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 provide assurances, however, that fluctuations in exchange rates will be fully offset by hedges or that currency movements and the

59

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 six months of 2002, foreign currencies in the U.K., Australia and New Zealand increased in value compared to the U.S. dollar by 4.8%, 10.1% and 17.4%, respectively (determined by the change in the exchange rates from December 31, 2001 to June 30, 2002). The increase in value of these currencies was the primary reason for the foreign currency translation gain of $79.3 million during the first six months 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 December 2002. At June 30, 2002, the outstanding notional amount of the contracts totaled $39.1 million and the fair value of the contracts totaled $(0.6) million. During the first six months of 2002, Contact Energy recognized a foreign exchange gain of $0.1 million related to the contracts that matured during the period.

        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.

        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 (in millions):

			June 30, 2002			December 31, 2001
			(Unaudited)
Derivatives:
	Interest rate:
		Interest rate swap/cap agreements	$	(24.6	)	$	(35.8	)
		Interest rate options		(0.2	)		(1.0	)
	Commodity price:
		Forwards		50.5			63.8
		Futures		(0.5	)		(8.4	)
		Options		0.2			0.4
		Swaps		(127.8	)		(137.6	)
	Foreign currency forward exchange agreements			(0.6	)		(0.6	)
	Cross currency interest rate swaps			3.9			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 into account quoted market prices, time

60

value of money, volatility of the underlying commodities and other factors. The following table summarizes the maturities, the valuation method and the related fair value of our risk management assets and liabilities (as of June 30, 2002) (in millions):

	Total Fair Value			Maturity <1 year		Maturity 1 to 3 years		Maturity 4 to 5 years			Maturity >5 years
	(Unaudited)
Assets:
Prices actively quoted	$	26.0		$	23.7	$	2.3	$	—		$	—
Prices based on models and other valuation methods		40.3			14.9		22.4		3.0			—
Total Assets	$	66.3		$	38.6	$	24.7	$	3.0		$	—
Liabilities:
Prices actively quoted	$	10.0		$	7.9	$	2.1	$	—		$	—
Prices based on models and other valuation methods		133.9			10.2		18.3		11.4			94.0
Total Liabilities	$	143.9		$	18.1	$	20.4	$	11.4		$	94.0
Grand Total	$	(77.6	)	$	20.5	$	4.3	$	(8.4	)	$	(94.0	)

        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 Derivative Financial Instruments

        On September 1, 2000, we acquired the trading operations of Citizens Power LLC and, subsequently, combined them with our trading and risk management operations, now conducted by our subsidiary, Edison Mission Marketing & Trading, Inc. As a result of a number of industry and credit related factors, we have minimized our trading activities and our price risk management activities with third parties not related to our power plants or investments in energy projects. See "—Industry Developments." To the extent we engage in trading activities, we seek to manage price risk and create stability of future income by selling electricity in the forward markets and, to a lesser degree, 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 purchase contracts and manage our exposure through a value at risk analysis as described further below.

        The fair value of the financial instruments, including forwards, futures, options and swaps, related to energy trading activities as of June 30, 2002 and December 31, 2001, which include energy commodities, are set forth below (in millions):

	June 30, 2002				December 31, 2001
	Assets		Liabilities		Assets		Liabilities
	(Unaudited)
Forward contracts	$	115.5	$	25.8	$	4.6	$	2.9
Futures contracts		—		0.1		0.1		0.1
Option contracts		0.8		0.2		—		—
Swap agreements		10.5		4.8		0.2		—
Total	$	126.8	$	30.9	$	4.9	$	3.0

        Quoted market prices are used to determine the fair value of the financial instruments related to energy trading activities, except for the power sales agreement with an unaffiliated electric utility that

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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. The following table summarizes the maturities, the valuation method and the related fair value of our energy trading assets and liabilities (as of June 30, 2002) (in millions):

	Total Fair Value		Maturity <1 year		Maturity 1 to 3 years		Maturity 4 to 5 years		Maturity >5 years
	(Unaudited)
Assets:
Prices actively quoted	$	13.9	$	13.9	$	—	$	—	$	—
Prices based on models and other valuation methods		115.4		4.3		7.7		10.2		93.2
Total Assets	$	129.3	$	18.2	$	7.7	$	10.2	$	93.2
Liabilities:
Prices actively quoted	$	11.3	$	11.3	$	—	$	—	$	—
Prices based on models and other valuation methods		22.1		6.9		4.3		3.7		7.2
Total Liabilities	$	33.4	$	18.2	$	4.3	$	3.7	$	7.2
Grand Total	$	95.9	$	—	$	3.4	$	6.5	$	86.0

        The net realized and unrealized gains or losses arising from energy trading activities for the three and six month periods ended June 30, 2002 and 2001 are as follows (in millions):

	Three Months Ended June 30,						Six Months Ended June 30,
	2002			2001			2002			2001
	(Unaudited)
Operating Revenues
Forward contracts	$	2.6		$	7.2		$	20.2		$	1.6
Futures contracts		(0.4	)		(0.4	)		(0.6	)		(1.9	)
Option contracts		(0.1	)		(0.3	)		(0.5	)		2.9
Swap agreements		4.4			—			3.9			(0.2	)
Total	$	6.5		$	6.5		$	23.0		$	2.4

        The unrealized gain (loss) from energy trading activities included in the above amounts was $(0.1) million for the three month periods ended June 30, 2002 and 2001, and $11.3 million and $(16.9) million for the six month periods ended June 30, 2002 and 2001, respectively.

Off-Balance Sheet Transactions

        For a discussion of Edison Mission Energy's off-balance sheet transactions, refer to "Off-Balance Sheet Transactions" on page 70 of Edison Mission Energy's Annual Report on Form 10-K for the fiscal year ended December 31, 2001.

Purchase of Equipment Under Lease

        On August 9, 2002, we exercised our option to purchase the Illinois peaker power units that were subject to a lease with a third-party lessor. As disclosed in "Off-Balance Sheet Transactions" in our 2001 Annual Report on Form 10-K, this lease was structured to maintain a minimum amount of equity (3% of the acquisition price) for the duration of the lease term in accordance with existing guidance for leases involving special purpose entities (sometimes referred to as synthetic leases). This transaction

62

represents the only synthetic lease that we had outstanding at June 30, 2002. The exercise of the purchase option resulted in the payment of $300 million to the owner-lessor, of which we received $255 million as repayment of the note receivable held by us. Accordingly, the net cash outlay required to exercise the purchase option was $45 million. The purchase of these peaker units will be recorded as an asset and depreciated over their estimated useful life. The annual increase to depreciation expense will be approximately $20 million.

Environmental Matters and Regulations

        For a discussion of Edison Mission Energy's environmental matters, refer to "Environmental Matters and Regulations" on page 74 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, except as follows:

        We have anticipated that upgrades to environmental controls at the Illinois Plants to reduce nitrogen oxide emissions would result in expenditures of approximately $317.5 million for the period 2003 - 2005. As a result of changes in the merchant energy marketplace, we are evaluating our capital expenditure program, including environmental improvements. At June 30, 2002, we have capitalized $33.5 million as construction in progress related to environmental improvements. We are currently updating our capital expenditure program and evaluating whether to proceed, delay or cancel individual projects. We expect to complete the update of our capital expenditure program by the end of 2002.

Critical Accounting Policies

        For a discussion of Edison Mission Energy's critical accounting policies, refer to "Critical Accounting Policies" on page 80 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 of the Financial Accounting Standards Board 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 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 agreements qualify as cash flow hedges. Under a cash flow hedge, we record the fair value of the forward sales agreements on our balance sheet and record the effective portion of the cash flow hedge as part of other comprehensive income. The ineffective portion of our cash flow hedges is recorded directly in our income statement. We implemented this interpretation on April 1, 2002. We recorded assets at fair value of $11.9 million, deferred taxes of $5.5 million and a $6.4 million increase to other comprehensive income as the cumulative effect of adoption of this interpretation.

        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. This implementation guidance became effective on April 1, 2002. The adoption of this implementation guidance had no impact on our financial statements.

        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

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requiring goodwill not to be amortized but rather tested for impairment at least annually at the reporting unit level. 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 completed the first step described above for each of the components of our goodwill. The fair value of the reporting units for the Contact Energy and First Hydro operations were in excess of related book value at January 1, 2002. Accordingly, no impairment of the goodwill related to these reporting units will be recorded upon adoption of this standard. We concluded that fair value of the reporting unit related to the Citizens Power acquisition was less than our book value and, accordingly, the goodwill related to this reporting unit is impaired at January 1, 2002. We are in the process of completing the second step of the impairment test described above, which will be completed by December 31, 2002.

        The following table sets forth what net income would have been exclusive of goodwill amortization for the three and six months ended June 30, 2002 and June 30, 2001.

	Three Months Ended June 30,				Six Months Ended June 30,
	2002		2001		2002			2001
	(Unaudited)
Reported net income (loss)	$	3.2	$	0.2	$	(32.6	)	$	8.8
Add back: Goodwill amortization, net of tax		—		2.2		—			4.4
Adjusted net income (loss)	$	3.2	$	2.4	$	(32.6	)	$	13.2

        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. The Statement 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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        For a discussion of market risk sensitive instruments, refer to "Market Risk Exposures" on page 59 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 Proceedings

        Sunrise Power Company, in which our wholly-owned subsidiary owns a 50% interest, sells all 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 Resources or, in the alternative, abrogated as of a future date, to allow for the possibility of renegotiation. After hearings and intermediate rulings, on July 23, 2002, the Federal Energy Regulatory Commission dismissed with prejudice the California Public Utilities Commission and California Electricity Oversight Board complaints against Sunrise. The California Public Utilities Commission and California Energy Oversight Board have a right of appeal to the federal courts of appeal within 60 days of the date of the order.

        On May 2, 2002, the United States Justice Foundation announced that it had filed a complaint in the Superior Court of the State of California, Los Angeles County, 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 the contracts entered into in 2001, as well as all 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.

        On May 15, 2002, Sunrise was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco by James M. Millar, "individually, and on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to the California Department of Water Resources, including Sunrise. The lawsuit alleges that the defendants, including Sunrise, engaged in unfair and fraudulent business practices by knowingly taking advantage of a manipulated power market to obtain unfair contract terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the defendants of excessive monies obtained by the defendants. Plaintiffs in several other class action lawsuits pending in Northern California have filed petitions seeking to have the Millar lawsuit consolidated with those lawsuits. The defendants in the Millar lawsuit and other class action suits removed all the lawsuits to the U.S. District Court, Northern District of California, and filed a motion to stay all proceedings pending final resolution of the jurisdictional issue. Various plaintiffs have filed pleadings opposing the removal and requesting that the matters be remanded to state court. The motions are still pending.

PMNC Litigation

        In February 1997, a civil action was commenced in the Superior Court of the State of California, Orange County, entitled The Parsons Corporation and PMNC v. Brooklyn Navy Yard Cogeneration Partners, L.P., Mission Energy New York, Inc. and B-41 Associates, L.P., Case No. 774980, in which the plaintiffs asserted general monetary claims under the construction turnkey agreement for the project in the amount of $136.8 million. Brooklyn Navy Yard has also filed an action entitled Brooklyn Navy Yard Cogeneration Partners, L.P. v. PMNC, Parsons Main of New York, Inc., Nab Construction Corporation,

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L.K. Comstock & Co., Inc. and The Parsons Corporation, in the Supreme Court of the State of New York, Kings County, Index No. 5966/97 asserting general monetary claims in excess of $13 million under the construction turnkey agreement. On March 26, 1998, the Superior Court in the California action granted PMNC's motion for attachment in the amount of $43 million against Brooklyn Navy Yard and attached a Brooklyn Navy Yard bank account in the amount of $0.5 million. Brooklyn Navy Yard is appealing the attachment order. On the same day, the court stayed all proceedings in the California action pending the New York action. PMNC's motion to dismiss the New York action was denied by the New York Supreme Court and further denied on appeal in September 1998. On March 9, 1999, Brooklyn Navy Yard filed a motion for partial summary judgment in the New York action. The motion was denied and Brooklyn Navy Yard has appealed. The appeal and the commencement of discovery were suspended until June 2000 to allow for voluntary mediation between the parties. The mediation ended unsuccessfully on March 23, 2000. On November 13, 2000, a New York appellate court issued a ruling granting summary judgment in favor of Brooklyn Navy Yard, striking PMNC's cause of action for quantum meruit, and limiting PMNC to its claims under the construction contract. On February 14, 2002, PMNC moved to amend the complaint in the New York action to add us as a defendant and to seek a $43 million attachment against us. This motion was heard on May 10, 2002, and the court issued an order denying the motion on June 21, 2002. On August 2, 2002, the court ordered that discovery be completed by mid-August 2002 and that the parties file dispositive motions on or before September 20, 2002. After ruling on the dispositive motions, the court plans to set a trial date. We agreed to indemnify Brooklyn Navy Yard and our partner in the venture from all claims and costs arising from or in connection with this litigation.

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, 2002, the PLN Labor Union filed to appeal this decision. Paiton Energy intends to contest the appeal.

BHP Fuel Supply Agreement Arbitration

        PT Batu Hitam Perkasa (BHP), one of our partners in Paiton Energy, has informed Paiton Energy that it intends to reactivate a pending arbitration to resolve disputes under the fuel supply agreement between BHP and Paiton Energy. The arbitration has been stayed since 1999 to allow the parties to engage in settlement discussions to restructure the coal supply chain for the Paiton project. These discussions did not result in a settlement of all potential claims with respect to the restructuring of the coal supply chain, and BHP recently requested that the arbitration tribunal permit BHP to amend or supplement its statement of claims to assert additional claims against Paiton Energy for breach, and termination, of the fuel supply agreement. BHP has not specified the amount of damages, or other relief, it seeks to recover. Paiton Energy intends to contest the arbitration.

        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
4.16	Participation Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P., Homer City OL1 LLC, as Facility Lessor and Ground Lessee, Wells Fargo Bank Northwest National Association, General Electric Capital Corporation, The Bank of New York as the Security Agent, The Bank of New York as Lease Indenture Trustee, Homer City Funding LLC and The Bank of New York as Bondholder Trustee, incorporated by reference to Exhibit 4.4 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.
4.16.1	Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 4.16 hereto, incorporated by reference to Exhibit 4.4.1 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.
4.17	Open-End Mortgage, Security Agreement and Assignment of Rents, dated as of December 7, 2001, among Homer City OL1 LLC, as the Owner Lessor to The Bank of New York, as Security Agent and Mortgagee, incorporated by reference to Exhibit 4.9 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.
10.10.1	Amendment to Power Purchase Agreement between P.T. Paiton Energy (formerly known as P.T. Paiton Energy Company) as Seller and P.T. PLN (Persero) (as successor to Perusahaan Umum Listrik Negara) as Buyer, dated as of June 28, 2002.
10.58.2	Amended and Restated Security Deposit Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P. and The Bank of New York as Collateral Agent, incorporated by reference to Exhibit 10.18.2 to the EME Homer City Generation L.P. Form 10-K for the year ended December 31, 2001.
10.102	Executive Grantor Trust Agreement, incorporated by reference to Exhibit 10.12 to the Edison International Form 10-K for the year ended December 31, 1995. (File No. 1-9936).
10.102.1	Executive Grantor Trust Agreement Amendment 2002-1, effective May 14, 2002, incorporated by reference to Exhibit 10.3 to the Edison International Form 10-Q for the quarter ended June 30, 2002. (File No. 1-9936).
10.103	Director Grantor Trust Agreement, incorporated by reference to Exhibit 10.10 to the Edison International Form 10-K for the year ended December 31, 1995. (File No. 1-9936).
10.103.1	Director Grantor Trust Agreement Amendment 2002-1, effective May 14, 2002, incorporated by reference to Exhibit 10.4 to the Edison International Form 10-Q for the quarter ended June 30, 2002. (File No. 1-9936).
99.1	Edison Mission Energy Distribution Summary for the years ended December 31, 2001 and 2000.

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99.2	Homer City Facilities Funds Flow From Operations for the twelve months ended June 30, 2002.
99.3	Homer City Facilities Funds Flow From Operations for the twelve months ended December 31, 2001.
99.4	Illinois Plants Funds Flow From Operations for the twelve months ended June 30, 2002.
99.5	Illinois Plants Funds Flow From Operations for the twelve months ended December 31, 2001.
99.6	Statement Pursuant to 18 U.S.C. Section 1350.

(b)  Reports on Form 8-K

        The registrant filed the following report on Form 8-K during the quarter ended June 30, 2002.

Date of Report	Date Filed	Item(s) Reported
May 10, 2002	May 16, 2002	4, 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)
By:	/s/ Kevin M. Smith Kevin M. Smith Senior Vice President, Chief Financial Officer and Treasurer
Date:	August 13, 2002

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QuickLinks

TABLE OF CONTENTS

PART I—FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In 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 JUNE 30, 2002

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

RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PART II—OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

SIGNATURES