Prepared by MERRILL CORPORATION

Edison Mission Energy
(Exact name of registrant as specified in its charter)

California (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)

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 /x/ No / /

Number of shares outstanding of the registrant's Common Stock as of August 13, 2001: 100 shares (all shares held by an affiliate of the registrant).

Item		Page
PART I—Financial Information
1.	Financial Statements	1
2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	18
3.	Quantitative and Qualitative Disclosures About Market Risk	48
PART II—Other Information
6.	Exhibits and Reports on Form 8-K	49
	Signatures	50

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In thousands)

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

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

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

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

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

EDISON MISSION ENERGY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2001

We have made all adjustments, including recurring accruals, 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, 2001 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, 2000 and 1999, included in our 2000 Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 2, 2001. We follow the same accounting policies for interim reporting purposes, with the exception of the change in accounting for derivatives (see Note 2). 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.

On June 8, 2001, Edison International created Mission Energy Holding Company as a wholly-owned indirect subsidiary. Mission Energy Holding's principal asset is our common stock. As previously disclosed by Edison International, in July 2001, Mission Energy Holding issued $800 million of 13.50% senior secured notes due 2008. Concurrently with the consummation of the offering of its senior secured notes, Mission Energy Holding borrowed $385 million under a new term loan. The senior secured notes and the term loan are secured by a first priority security interest in our common stock. The respective rights, remedies and priorities of the holders of the senior secured notes and the lenders with respect to our stock are governed by intercreditor arrangements. Both the senior secured notes and the term loan also have security interests in interest reserve accounts, covering the interest payable on those obligations for the first two years. We have not guaranteed either the senior secured notes or the term loan, both of which are non-recourse to us. The net proceeds of the offering and the term loan not deposited into the respective interest escrow accounts were used to pay a dividend to Mission Energy Holding's parent, The Mission Group, which in turn loaned the net proceeds to its parent, Edison International. Edison International used the funds to repay a portion of its indebtedness that matures in 2001. The Mission Energy Holding financing documents contain restrictions on our ability and the ability of our subsidiaries to enter into specified transactions or engage in specified business activities and require in some instances that we obtain the approval of the Mission Energy Holding board of directors. Our articles of incorporation bind us to the restrictions in the Mission Energy Holding financing documents by restricting our ability to enter into specified transactions or engage in specified business activities, as set forth in the Mission Energy Holding financing documents, without shareholder approval.

Edison International, our ultimate parent company, is a holding company. Edison International is also the corporate parent of Southern California Edison Company, an electric utility that buys and sells power in California. In the past year, various market conditions and other factors have resulted in higher wholesale power prices to California utilities. At the same time, two of the three major California utilities, Southern California Edison and Pacific Gas and Electric Co., have operated under a retail rate freeze. As a result, there has been a significant under recovery of costs by Southern

California Edison and Pacific Gas and Electric, and each of these companies has failed to make payments due to power suppliers, including us, and others. Given these and other payment defaults, Southern California Edison could face bankruptcy at any time. Pacific Gas and Electric filed a voluntary bankruptcy petition on April 6, 2001. Other results of the under recoveries could include an end to the retail rate freeze and significant retail rate increases. A number of federal and state, legislative and regulatory initiatives addressing the issues of the California electric power industry have been proposed, including wholesale rate caps, retail rate increases, acceleration of power plant permitting and state entry into the power market. Many of these activities are ongoing. These activities may result in a restructuring of the California power market. At this time, these activities are in their preliminary stages, and it is not possible to estimate their likely ultimate outcome. For more information on how the current California power crisis affects us and our investments, see "—Note 6. Commitments and Contingencies—The California Power Crisis."

Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." The Statement 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. The Statement 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. The ineffective portion of a derivative's change in fair value is immediately recognized in earnings.

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 record all derivatives at fair value unless the derivatives qualify 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, as amended, are met. The majority of our physical long-term power and fuel contracts, and the similar business activities of our affiliates, qualify under this exception.

plants in the United Kingdom and fuel contracts related to the Collins Station in Illinois do not qualify for either the normal purchases and sales exception or as cash flow hedges. In both these situations, we could not conclude, based on information available at June 30, 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 are recorded at fair value, with subsequent changes in fair value reflected in net gains (losses) from energy trading and price risk management in the consolidated income statement.

As a result of the adoption of SFAS No. 133, we expect our quarterly earnings will be more volatile than earnings reported under our prior accounting policy. We recorded a $6 million, after tax, increase to net income as the cumulative change in the accounting for derivatives during the quarter ended March 31, 2001. In addition, we recorded a $230 million, after tax, unrealized holding loss upon adoption of a change in accounting principle reflected in accumulated other comprehensive loss in the consolidated balance sheet. During the quarter ended June 30, 2001, we recorded a $120 million, after tax, unrealized holding gain reflected in accumulated other comprehensive loss in the consolidated balance sheet. We recorded a loss of $0.3 million, after tax, and $7.4 million, after tax, for the quarter ended and six months ended June 30, 2001, respectively, as the change in the fair value of derivatives required under SFAS No. 133 that previously qualified for hedge accounting. We also recorded a net gain of $1.5 million and $1.6 million for the quarter ended and six months ended June 30, 2001, respectively, representing the amount of cash flow hedges' ineffectiveness, reflected in net gains (losses) from energy trading and price risk management in the consolidated income statement.

The Derivative Implementation Group of the Financial Accounting Standards Board has recently provided guidance on the normal sales and purchases exception that affects classification on commodity contracts. We did not use the normal sales and purchases exception for forward sales contracts from our Homer City plant due to our net settlement procedures with counterparties for the period between January 1, 2001 through June 30, 2001. Effective July 1, 2001, the Derivative Implementation Group of the Financial Accounting Standards Board extended the normal sales and purchases exception to include forward sales contracts subject to net settlement procedures with counterparties. Accordingly, we intend to use the normal sales and purchases exception for our Homer City forward sales contracts commencing July 1, 2001 and plan to record a cumulative change in the accounting for derivatives during the quarter ended September 30, 2001. We are currently evaluating the impact of the implementation guidance on our remaining commodity contracts, which would be accounted for on a prospective basis.

Through December 31, 1999, we accrued for major maintenance costs incurred during the period between turnarounds (referred to as "accrue in advance" accounting method). In March 2000, we voluntarily decided to change our accounting policy to record major maintenance costs as an expense as incurred. This change in accounting policy is considered preferable based on guidance provided by the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes," we recorded a $17.7 million, after tax, increase to net income, as a cumulative change in the accounting for major maintenance costs during the quarter ended March 31, 2000.

Inventory is stated at the lower of weighted average cost or market. Inventory at June 30, 2001 and December 31, 2000 consisted of the following:

	June 30, 2001		December 31, 2000
	(Unaudited)
	(in millions)
Coal and fuel oil	$	252.5	$	207.8
Spare parts, materials and supplies		74.7		72.1

Total	$	327.2	$	279.9

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, 2000	$	(146.8	)	$	—		$	(146.8	)
Current period change		(101.2	)		(118.1	)		(219.3	)

Balance at June 30, 2001 (Unaudited)	$	(248.0	)	$	(118.1	)	$	(366.1	)

Unrealized gains (losses) on cash flow hedges at June 30, 2001 included forward sales contracts from our Homer City plant that did not meet the normal sales and purchases exception under SFAS No. 133 due to our net settlement procedures with counterparties. In addition, the hedge agreement we have with the State Electricity Commission of Victoria for electricity prices from our Loy Yang B project in Australia qualifies as a cash flow hedge. This contract also could not qualify under the normal sales and purchases exception because financial settlement of the contract occurs without physical delivery. Approximately 93% of our accumulated other comprehensive loss at June 30, 2001 related to net unrealized losses on cash flow hedges resulting from these contracts. These net losses arise from current forecasts of future electricity prices in these markets greater than our contract prices. Although the contract prices are below the current market prices, we believe that prices included in our contracts mitigate price risk associated with future changes in market prices and are at prices that meet our profit objectives. Assuming the long-term contract with the State Electricity Commission of Victoria continues to qualify as a cash flow hedge, future changes in the forecast of market prices for contract volumes included in this agreement will increase or decrease our other comprehensive income without significantly affecting our net income.

As our hedged positions are realized, approximately $11.9 million, after tax, of the net unrealized losses on cash flow hedges will be reclassified into earnings during the remainder of 2001. Management expects that these net unrealized losses will be offset when the hedged items are recognized in earnings. The maximum period over which a cash flow hedge is designated, excluding those forecasted transactions related to the payment of variable interest on existing financial instruments, is 15 years.

In February 2001, we completed the acquisition of a 50% interest in CBK Power Co. Ltd. in exchange for $20 million. CBK Power has entered into a 25-year build-rehabilitate-transfer-and-operate agreement with National Power Corporation related to the 728 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric project located in the Philippines. Financing for this $460 million project comprises equity commitments of $117 million (our 50% share is $58.5 million) required to be made upon completion of the rehabilitation and expansion, currently scheduled in 2003, and debt financing which is in place for the remainder of the cost for this project.

During the second quarter of 2001, we completed the purchase of additional shares of Contact Energy for NZ$152 million, thereby increasing our ownership interest from 42.6% to 51.2%. Accordingly, we began accounting for Contact Energy on a consolidated basis effective June 1, 2001, upon acquisition of a controlling interest. Prior to June 1, 2001, we used the equity method of accounting for Contact Energy. In order to finance this purchase, we obtained a NZ$135 million, 364-day bridge loan from an investment bank under a credit facility which is to be syndicated by the bank. In addition to other security arrangements, a security interest over all Contact Energy shares held has been provided as collateral. In June and July 2001, we issued through one of our subsidiaries new preferred securities to repay the bridge loan. On July 2, 2001, we redeemed NZ$400 million EME Taupo preferred securities from the existing holders. Funding for the redemption of the existing preferred securities was provided by a NZ$400 million credit facility scheduled to mature in July 2005. The financing documents governing the credit facility provide that the credit facility may be funded under either, or a combination of, a letter of credit facility or a revolving credit facility. The NZ$400 million was originally funded as a revolving credit facility.

On June 25, 2001, Texaco Power & Gasification Holdings Inc. repurchased a 50% interest in the Sunrise project for $84 million, which amount totaled 50% of the project costs, prior to commercial operations. Commercial operations commenced on June 27, 2001. On June 25, 2001, we entered into a long-term power purchase agreement with the California Department of Water Resources. The total estimated construction cost of this project through 2003 is approximately $455 million. The project intends to obtain project financing for a portion of the capital costs.

On June 29, 2001, we completed the sale of our 25% interest in the Hopewell project to the existing partner. Proceeds from the sale were $26.5 million. We recorded a gain on the sale of $5.4 million ($2.8 million after tax).

Subsequent to June 30, 2001, we have entered into agreements, subject to obtaining consents from third parties and other conditions precedent to closing, for the sale of our interests in the EcoEléctrica, Gordonsville, Commonwealth Atlantic, James River and Saguaro projects. In addition, we are currently offering for sale our interests in the Brooklyn Navy Yard and Nevada Sun-Peak projects. We expect the proceeds from the sale of our interests in the above projects, if completed, will be in excess of our book value ($482 million at June 30, 2001). We are also offering for sale the Ferrybridge and Fiddler's Ferry plants in the United Kingdom. See "Management's Discussion and Analysis of Financial

Condition and Results of Operations—Liquidity and Capital Resources—Subsidiary Financing Plans—Status of Edison First Power Loan."

The following table summarizes our consolidated capital commitments as of June 30, 2001. Details regarding these capital commitments are discussed in the sections referenced.

Type of Commitment	Estimated Cost in U.S. $	Time Period	Discussed Under
	(in millions)
New Gas-Fired Generation	$250	by 2003	Illinois Plants—Power Purchase Agreements, included in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the year ended December 31, 2000
New Gas-Fired Generation	986*	2001-2004	Edison Mission Energy Master Turbine Lease, included in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the year ended December 31, 2000
Environmental Improvements at our Project Subsidiaries	494	2001-2005	Management's Discussion and Analysis of Financial Condition and Results of Operations—Environmental Matters and Regulations
Project Acquisition for the Italian Wind Projects	8	2001-2002	Firm Commitment for Asset Purchase
Equity Contribution for the Sunrise Project	123	2001-2003	Firm Commitments to Contribute Project Equity
Equity Contribution for the Italian Wind Projects	1	2001-2002	Firm Commitments to Contribute Project Equity
Equity Contribution for the CBK Project	59	2003	Firm Commitments to Contribute Project Equity

Project		Local Currency		U.S. Currency
				(in millions)
Italian Wind Projects(i)		18 billion Italian Lira		$	7.9

Project	Local Currency	U.S. Currency
		(in millions)
Italian Wind Projects(i)	3 billion Italian Lira	$	1.4
CBK Project(ii)	—		58.5
Sunrise Project(iii)	—		122.9

Firm commitments to contribute project equity could be accelerated due to events of default as defined in the non-recourse project financing facilities. Management does not believe that these events of default will occur to require acceleration of the firm commitments.

guarantee will be available until December 31, 2001, after which time Edison Mission Energy will have no further obligations under this guarantee. To satisfy the requirements under the Edison Mission Holdings Co. bank financing to have a debt service reserve account balance in an amount equal to six months' debt service, Edison Mission Energy provides a guarantee of Edison Mission Holdings' obligations in the amount of $9 million to the lenders involved in the bank financing.

Our 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 us. The majority of Edison Mission Marketing & Trading's contracts have various standards of creditworthiness, including the maintenance of specified credit ratings. If Edison Mission Marketing & Trading does not maintain its investment grade rating or if other events adversely affect its financial position, a third party could request Edison Mission Marketing & Trading to provide adequate assurance. Adequate assurance could take the form of supplying additional financial information, additional guarantees, collateral, letters of credit or cash. Failure to provide adequate assurance could result in a counterparty liquidating an open position and filing a claim against Edison Mission Marketing & Trading for any losses.

The California power crisis has adversely affected the liquidity of West Coast trading markets and, to a lesser extent, other regions in the United States. Our trading and price risk management activity has been reduced as a result of these market conditions and uncertainty regarding the effect of the power crisis on our affiliate, Southern California Edison. It is not certain that resolution of the California power crisis will occur in 2001 or that, if resolved, we will be able to conduct trading and price risk management activities in a manner that will be favorable to us.

Some of our subsidiaries have entered into indemnification agreements, under which the subsidiaries have 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, 2001, if payment were required, would be $246 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.

In support of the businesses of our subsidiaries, we have made, from time to time, guarantees, and have entered into indemnity agreements with respect to our subsidiaries' obligations like those for debt service, fuel supply or the delivery of power, and have entered into reimbursement agreements with respect to letters of credit issued to third parties to support our subsidiaries' obligations. We may incur

additional guaranty, indemnification, and reimbursement obligations, as well as obligations to make equity and other contributions to projects in the future.

In the past year, various market conditions and other factors have resulted in higher wholesale power prices to California utilities. At the same time, two of the three major California utilities, Southern California Edison and Pacific Gas and Electric, have operated under a retail rate freeze. As a result, there has been a significant under recovery of costs by Southern California Edison and Pacific Gas and Electric, and each of these companies has failed to make payments due to power suppliers, including us, and others. Given these and other payment defaults, Southern California Edison could face bankruptcy at any time. Pacific Gas and Electric filed a voluntary bankruptcy petition on April 6, 2001. Edison International, our ultimate parent company, is also the corporate parent of Southern California Edison. For a description of this contingency and the California power crisis, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—The California Power Crisis and Our Response."

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. Our investment in the Paiton project was $503 million at June 30, 2001. Paiton Energy is in continuing negotiations on a long-term restructuring of the tariff under a long-term power purchase agreement with the state-owned electric utility company, PT PLN. Paiton Energy and PT PLN agreed on a Phase I Agreement for the period from January 1, 2001 through June 30, 2001. This agreement provided for fixed monthly payments aggregating $108 million over its six-month duration and for the payment for energy delivered to PT PLN from the plant during this period. PT PLN made all fixed payments due under the Phase I Agreement totaling $108 million as scheduled. Paiton Energy received lender approval of the Phase I Agreement, and Paiton Energy has also entered into a lender interim agreement under which lenders have effectively agreed to interest-only payments and to deferral of principal payments while Paiton Energy and PT PLN seek a long-term restructuring of the tariff. The lenders have agreed to extend that agreement through December 31, 2001. Paiton Energy and PT PLN intended to complete the negotiations of the future phases of a new long-term tariff during the six-month duration of the Phase I Agreement. Although Paiton Energy and PT PLN did not complete negotiations on a long-term restructuring of the tariff by June 30, 2001, Paiton Energy and PT PLN have signed an agreement providing for an extension of the Phase I Agreement from July 1, 2001 to September 30, 2001. Paiton Energy is continuing to generate electricity to meet the power demand in the region and believes that PT PLN will continue to agree to make payments for electricity on an interim basis beyond June 30, 2001 while negotiations regarding the long-term restructuring of the tariff continue. Although completion of negotiations may be delayed, Paiton Energy continues to believe that negotiations on the long-term restructuring of the tariff will be successful. For a more detailed discussion of the restructuring of the tariff and related matters, refer to "Commitments and

Contingencies—Paiton" in Item 7. of Edison Mission Energy's Annual Report on Form 10-K for the fiscal year ended December 31, 2000.

Any material modifications of the power purchase agreement resulting from the continuing negotiation of a new long-term tariff could require a renegotiation of the Paiton project's debt agreements. The impact of any such renegotiations with PT PLN, the Government of Indonesia or the project's creditors on our expected return on our investment in Paiton Energy is uncertain at this time; however, we believe that we will ultimately recover our investment in the project.

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

Project	Local Currency	U.S. Currency
		(in millions)
Paiton(i)	—	$	5.3
ISAB(ii)	84 billion Italian Lira		36.5

We are not aware of any other significant contingent obligations or obligations to contribute project equity other than as noted above and equity contributions to be made by us to meet capital calls by partnerships who own qualifying facilities that have power purchase agreements with Southern California Edison and Pacific Gas and Electric. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—The California Power Crisis and Our Response" for further discussion.

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

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 in, respectively.

	Three Months Ended June 30,				Six Months Ended June 30,
	2001		2000		2001		2000
	(Unaudited) (in millions)
Operating Revenues	$	418.0	$	177.3	$	794.2	$	293.8
Operating Income		151.2		52.7		231.1		88.7
Net Income		151.3		60.0		231.2		95.6

The following table presents summarized financial information of the significant subsidiary investment in oil and gas accounted for by the equity method. The significant subsidiary is Four Star Oil & Gas Company, of which we own 36 percent.

	Three Months Ended June 30,				Six Months Ended June 30,
	2001		2000		2001		2000
	(Unaudited) (in millions)
Operating Revenues	$	85.8	$	91.8	$	198.0	$	169.7
Operating Income		55.7		50.9		142.4		91.2
Net Income		31.9		31.7		88.7		55.9

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

The following discussion contains forward-looking statements. These statements are based on our current plans and expectations and involve risks and uncertainties that 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.

We are an independent power producer engaged in the business of developing, acquiring, owning or leasing and operating electric power generation facilities worldwide. We also conduct energy trading and price risk management activities in power markets open to competition. Edison International is our ultimate parent company. Edison International also owns Southern California Edison Company, one of the largest electric utilities in the United States. We were formed in 1986 with two domestic operating projects. As of June 30, 2001, we owned interests in 33 domestic and 39 international operating power projects with an aggregate generating capacity of 27,798 megawatts (MW), of which our share was 22,923 MW. At that date, one domestic and five international projects, totaling 1,551 MW of generating capacity, of which our anticipated share will be approximately 926 MW, were in construction. At June 30, 2001, we had consolidated assets of $15.3 billion and total shareholder's equity of $2.7 billion.

Our operating revenues are derived primarily from electric revenues and equity in income from power projects. Electric revenues accounted for 83% and 95% of our total operating revenues during the three-month periods ended June 30, 2001 and 2000, respectively, and 85% and 94% of our total operating revenues during the six-month periods ended June 30, 2001 and 2000, respectively. Our consolidated operating revenues during those years also include equity in income from oil and gas investments, net gains (losses) from energy trading and price risk management activities and revenues attributable to operation and maintenance services.

matures in 2001. The Mission Energy Holding financing documents contain restrictions on our ability and the ability of our subsidiaries to enter into specified transactions or engage in specified business activities and require in some instances that we obtain the approval of the Mission Energy Holding board of directors. Our articles of incorporation bind us to the restrictions in the Mission Energy Holding financing documents by restricting our ability to enter into specified transactions or engage in specified business activities, as set forth in the Mission Energy Holding financing documents, without shareholder approval.

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 those entities.

Operating revenues decreased $11.1 million for the second quarter ended June 30, 2001, compared to the corresponding period of 2000. The decrease was primarily due to lower dispatch from the coal units at the Illinois Plants as a result of lower market prices during the second quarter of 2001. Operating revenues increased $50.1 million for the six months ended June 30, 2001, compared to the same prior year period. The increase resulted from higher electric revenues from the Homer City plant due to higher energy prices and from the Illinois Plants due to increased generation from the coal units as a result of higher market prices, as compared to the same prior year period.

Net gains from energy trading activities were $6.5 million and $2.4 million for the second quarter and six months ended June 30, 2001, respectively. There were no comparable gains or losses for the same prior year periods. Total gains and losses from price risk management activities increased $39.2 million and $63.9 million for the second quarter and six months ended June 30, 2001, respectively, compared to the corresponding periods of 2000. The increase in gains was primarily due to

realized and unrealized gains for a gas swap purchased to hedge a portion of our gas price risk related to our share of gas production in Four Star, an oil and gas company in which we have a minority interest and which we account for under the equity method. Although we believe the gas swap hedges our gas price risk, hedge accounting is not permitted for our investments accounted for on the equity method. Partially offsetting this gain in the second quarter and six months ended June 30, 2001 was a loss resulting from the change in market value of future contracts with respect to fuel purchases at the Illinois Plants that did not qualify for hedge accounting under SFAS No. 133.

Equity in income from investments increased $49 million and $98 million during the second quarter and six months ended June 30, 2001, respectively, compared to the same prior year periods. The increase was primarily the result of higher revenues from cogeneration projects due to higher energy pricing during the six-month period ended June 30, 2001, and higher revenues from oil and gas investments due to higher oil and gas prices in the first quarter of 2001.

Due to warmer weather during the summer months, electric revenues generated from the Homer City plant 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 for our West Coast power investments.

Fuel and plant operations increased $19.2 million and $76.9 million for the second quarter and six months ended June 30, 2001, respectively, compared to the corresponding periods of the prior year. The increase in plant operations resulted from lease costs related to the sale-leaseback commitments for the Powerton-Joliet power facilities and the Collins gas and oil-fired power plant. There were no comparable lease costs for the Powerton-Joliet power facilities during the six months ended June 30, 2000. In addition, plant operations increased due to higher major maintenance costs at the Illinois Plants during the six-month period ended June 30, 2001. The increase in fuel expense for the six months ended June 30, 2001, as compared to the same period last year, resulted from higher fuel costs at the Illinois Plants primarily due to higher natural gas and fuel oil prices.

Depreciation and amortization expense decreased $10.2 million and $20.9 million for the second quarter and six months ended June 30, 2001, respectively, compared to the same periods last year. The decrease resulted from lower depreciation expense at the Illinois Plants related to the sale-leaseback transaction for the Powerton-Joliet power facilities to third-party lessors in August 2000.

Administrative and general expenses for the quarter ended and six months ended June 30, 2001 consist of administrative and general expenses incurred at our trading operations in Boston, Massachusetts. Prior to September 1, 2000, the acquisition date of Citizens Power, administrative and general expenses incurred by our own marketing operations were reflected in Corporate/Other administrative and general expenses.

Operating income increased $69.5 million and $147.5 million during the second quarter and six months ended June 30, 2001, respectively, compared to the corresponding periods of the prior year. The increase was primarily due to operating income from the Homer City plant, equity in income from investments in energy projects and gains from price risk management activities discussed above.

Operating revenues increased $51.6 million and $45.5 million for the second quarter and six months ended June 30, 2001, respectively, compared to the corresponding periods of 2000. The increase was primarily due to consolidating Contact Energy operating revenues due to acquiring a controlling interest in the project, effective June 1, 2001. The increase was partially offset by lower electric revenues from the Loy Yang B plant in Australia due to a 14.4% decrease in the average exchange rate of the Australian dollar compared to the U.S. dollar at the six-month period ended June 30, 2001, compared to the same prior year period.

Net gains from price risk management activities were $0.6 million and $0.1 million for the second quarter and six months ended June 30, 2001, respectively. There were no comparable gains or losses for the same prior year periods. The gains primarily represent the ineffective portion of a long-term contract with the State Electricity Commission of Victoria and interest rate swaps entered into by the Loy Yang B plant, which are derivatives that qualified as cash flow hedges under SFAS No. 133. See "—Note 4. Accumulated Other Comprehensive Income (Loss)," for further discussion.

Equity in income from investments increased $2.2 million and $2.6 million during the second quarter and six months ended June 30, 2001, respectively, compared to the same prior year periods. The increase primarily reflects gains from Contact Energy through May 31, 2001 due to higher wholesale electricity prices in the current year.

Fuel and plant operations increased $27.5 million and $25.7 million for the second quarter and six months ended June 30, 2001, respectively, compared to the corresponding periods of 2000. The increase was primarily due to consolidating Contact Energy operating expenses, effective June 1, 2001.

Operating income increased $26 million and $24 million during the second quarter and six months ended June 30, 2001, respectively, compared to the corresponding periods of 2000. The increase was primarily due to consolidating Contact Energy results of operations, effective June 1, 2001. Prior to June 1, 2001, we used the equity method of accounting for Contact Energy.

Operating revenues decreased $47.9 million and $128.1 million for the second quarter and six months ended June 30, 2001, respectively, compared to the corresponding periods of the prior year. The decrease resulted primarily from lower electric revenues from the Ferrybridge and Fiddler's Ferry plants and the First Hydro plant due to lower energy prices and an 8.2% decrease in the average exchange rate of the pound sterling compared to the U.S. dollar at the six-month period ended June 30, 2001, compared to the same prior year period. The time weighted average System Marginal Price decreased from £21.3/MWh during the quarter ended March 31, 2000 to £18.6/MWh during the quarter ended March 31, 2001. 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, therefore eliminating the System Marginal Price. The new electricity trading arrangements are described in further detail under "—Market Risk Exposures—United Kingdom." These new electricity trading arrangements have resulted in lower forward contract prices for the quarter ended June 30, 2001, compared to the quarter ended June 30, 2000. The First Hydro plant, Ferrybridge and Fiddler's Ferry plants and the Iberian Hy-Power plants generally provide higher electric revenues during the winter months.

Net losses from price risk management activities were $3.9 million and $14.1 million for the second quarter and six months ended June 30, 2001, respectively. There were no comparable gains or losses for the same prior year periods. The losses primarily represent the change in market value of electricity rate swap agreements that were recorded at fair value under SFAS No. 133 with changes in fair value recorded through the income statement.

Equity in income from investments increased $5.9 million and $4 million during the second quarter and six months ended June 30, 2001, respectively, compared to the same prior year periods. The increase reflects lower losses during the second quarter ended June 30, 2001, compared to the corresponding period in 2000 from the ISAB project, which commenced operations in April 2000. We had no comparable results for the ISAB project in the first quarter of 2000.

Fuel and plant operations increased $25.5 million for the quarter ended June 30, 2001, compared to the corresponding period in 2000. The increase in fuel expense resulted from higher fuel costs at the Doga plant due to increased production in the second quarter of 2001, compared to the same prior year quarter, when the plant experienced more unplanned outages. In addition, fuel costs increased at the First Hydro plant due to higher overnight prices and imbalance charges. The increase in plant

operations resulted primarily from higher overhaul costs at the Ferrybridge and Fiddler's Ferry plants during the quarter ended June 30, 2001, compared to the corresponding period in 2000.

Fuel and plant operations decreased $1.3 million for the six months ended June 30, 2001, compared to the same prior year period. The decrease in fuel expense and plant operations resulted primarily from a decrease in the average exchange rate of the pound sterling compared to the U.S. dollar. In addition, plant operations decreased from lower production at the Ferrybridge and Fiddler's Ferry plants during the first six months of 2001. Partially offsetting these decreases were higher fuel costs and plant operation expenses for the Doga plant due to increased production in the first six months of 2001, compared to the same prior year period.

Operating income decreased $72.2 million and $135.2 million during the second quarter and six months ended June 30, 2001, respectively, compared to the same prior year periods. The decrease was due to lower operating income from the Ferrybridge and Fiddler's Ferry plants, the First Hydro plant and the Doga plant.

Net gains from price risk management activities were $0.4 million and $1.3 million for the second quarter and six months ended June 30, 2001, respectively. There were no comparable gains or losses for the same prior year periods. The gains primarily resulted from the change in market value of our interest rate swaps with respect to our $100 million senior notes that did not qualify for hedge accounting under SFAS No. 133.

Long-term incentive compensation expense consists of charges related to our terminated phantom option plan. We recorded an adjustment to our long-term incentive compensation accrual during the six months ended June 30, 2001 for changes in the market value of stock equivalent units.

Administrative and general expenses decreased $6.3 million and $8.7 million for the second quarter and six months ended June 30, 2001, respectively, compared to the corresponding periods of 2000. The decrease was the result of lower administrative and general operating costs.

Interest and other income increased $5.5 million for the six months ended June 30, 2001, compared to the same prior year period. The increase was primarily due to higher interest income and foreign exchange gains on intercompany loans. Higher interest income resulted from the $255 million of notes purchased in connection with the sale-leaseback of the Illinois peaker power units in July 2000.

On June 30, 2000, we completed the sale of our 50% interest in the Auburndale project to the existing partner. Proceeds from the sale were $22 million. We recorded a gain on the sale of $17.0 million ($10.5 million after tax).

Interest expense decreased $18.5 million and $37.7 million for the second quarter and six months ended June 30, 2001, respectively, compared to the same prior year periods. The decrease was primarily the result of payment on our $500 million floating rate notes issued in December 1999 and subsequently paid in September 2000, lower interest rates on debt financing associated with the Illinois Plants and favorable changes in foreign exchange rates.

Minority interest expense increased $6.5 million and $6.1 million for the second quarter and six months ended June 30, 2001, respectively, compared to the same prior year periods. The increase was due to accounting for Contact Energy on a consolidated basis, effective June 1, 2001, due to the purchase of additional shares of Contact Energy that resulted in our ownership interest increasing from 42.6% to 51.2%.

During the six months ended June 30, 2001, we recorded an effective tax provision rate of 39% based on projected income for the year and benefits under our tax sharing agreement, compared to the annual effective tax benefit rate for the first six months of 2000 of 36%.

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.

we record all derivatives at fair value unless the derivatives qualify 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, as amended, are met. The majority of our physical long-term power and fuel contracts, and the similar business activities of our affiliates, qualify under this exception.

The majority of our remaining risk management activities, including forward sales contracts from our Homer City plant, qualify for treatment under SFAS No. 133 as cash flow hedges with appropriate adjustments made to other comprehensive income. The hedge agreement we have with the State Electricity Commission of Victoria for electricity prices from our Loy Yang B project in Australia qualifies as a cash flow hedge. This contract could not qualify under the normal sales and purchases exception because financial settlement of the contract occurs without physical delivery. Some of our derivatives did not qualify for either the normal sales and purchases exception or as cash flow hedges. These derivatives are recorded at fair value with subsequent changes in fair value recorded through the income statement. The majority of our activities related to the Ferrybridge and Fiddler's Ferry power plants in the United Kingdom and fuel contracts related to the Collins Station in Illinois do not qualify for either the normal purchases and sales exception or as cash flow hedges. In both these situations, we could not conclude, based on information available at June 30, 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 are recorded at fair value, with subsequent changes in fair value reflected in net gains (losses) from energy trading and price risk management in the consolidated income statement.

Through December 31, 1999, we accrued for major maintenance costs incurred during the period between turnarounds (referred to as "accrue in advance" accounting method). In March 2000, we

voluntarily decided to change our accounting policy to record major maintenance costs as an expense as incurred. This change in accounting policy is considered preferable based on guidance provided by the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes," we recorded a $17.7 million, after tax, increase to net income, as a cumulative change in the accounting for major maintenance costs during the quarter ended March 31, 2000.

At June 30, 2001, we had cash and cash equivalents of $573.4 million and had available a total of $16 million of borrowing capacity under one of our three revolving senior credit facilities. We had no borrowing capacity under our other two credit facilities. One of our credit facilities was originally scheduled to mature in March 2001 but was extended twice: first to May 2001 and then to October 2001. One of our other credit facilities was originally scheduled to mature in May 2001 but was also extended to October 2001. Currently, all three of these credit facilities are scheduled to mature on October 10, 2001. We are obligated to the lenders under our credit facilities to repay indebtedness, and concurrently reduce the outstanding commitments under these credit facilities to $1 billion by August 15, 2001. See "—Corporate Financing Plans."

In April 2001, we issued $600 million of 9.875% senior notes, due in 2011. We used the proceeds of that offering to repay indebtedness, including mandatory repayments of $225 million, which also permanently reduced the amount available under our credit facilities. As a result of the mandatory repayments, the credit facilities were reduced from $1.5 billion to $1.275 billion. In connection with the sale of our 25% interest in the Hopewell project and a 50% interest in the Sunrise project, our credit facilities were further reduced to $1.224 billion. On August 10, 2001, we issued $400 million of 10% senior notes, due in 2008. We used the proceeds to permanently repay indebtedness under our corporate credit facilities, reducing the outstanding commitments under these facilities to $823.3 million.

Net cash used in operating activities totaled $372.1 million during the six months ended June 30, 2001, compared to net cash provided by operating activities of $68.4 million for the corresponding period of the prior year. The decrease is primarily due to higher working capital requirements. Net working capital at June 30, 2001 was ($1,160.5) million compared to ($1,703.9) million at December 31, 2000.

Net cash provided by financing activities decreased to $381.4 million for the six months ended June 30, 2001 from $524.6 million for the six months ended June 30, 2000. In January 2000, one of our foreign subsidiaries borrowed $242.7 million from Edison Capital, an indirect affiliate. During the first quarter of 2001, the subordinated financing was repaid with interest. In April 2001, we issued $600 million of 9.875% senior notes due 2011, the proceeds of which were used to permanently repay $225 million on our corporate credit facilities. In June 2001, an additional $51 million was permanently repaid on our corporate credit facilities. In addition, dividends totaling $65 million were paid to The Mission Group and ultimately to Edison International, our ultimate parent company, during the six-month period ended June 30, 2001, compared to $44 million during the same prior year period. As of June 30, 2001, we had recourse debt of $2.5 billion, with an additional $6.1 billion of non-recourse debt (debt which is recourse to specific assets or subsidiaries, but not to Edison Mission Energy) on our consolidated balance sheet.

Net cash used in investing activities increased to $347.5 million for the six months ended June 30, 2001 from $307.6 million for the six months ended June 30, 2000. The increase is primarily due to the equity contributions made by us to meet capital calls by partnerships who own qualifying facilities that have power purchase agreements with Southern California Edison and Pacific Gas and Electric during

the six-month period ended June 30, 2001. See "—The California Power Crisis and Our Response" for further discussion. Through June 30, 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. Through June 30, 2000, $27 million was paid towards the purchase price and $13 million in equity contributions for the Italian Wind Projects and $33.5 million was made in equity contributions for the EcoEléctrica project. In June 2001, we also completed the sale of a 50% interest in the Sunrise project to Texaco for $84 million. We invested $113.2 million and $178.5 million during the six-month period ended June 30, 2001 and 2000, respectively, in new plant equipment principally related to the Homer City plant and Illinois Plants.

As discussed above, we have three corporate credit facilities scheduled to expire on October 10, 2001 with an aggregate amount of commitments of $1.224 billion thereunder as of June 30, 2001, which we have committed to reduce to $1 billion in the aggregate by August 15, 2001. Our corporate cash requirements in 2001 are expected to exceed cash distributions from our subsidiaries. In addition to the commitment to pay down the corporate credit facilities by $224 million, our expected corporate cash payments for the remainder of 2001 include:

We used the proceeds from the August 2001 offering of senior notes to pay down a portion of our existing corporate credit facilities. In addition, we have selected a syndicate of bank lenders to implement a new $750 million credit facility. We plan to use this new facility, together with other corporate funds, to replace the balance under our existing corporate credit facilities. Completion of this new credit facility is subject to a number of conditions. Although we believe our corporate financing plans will be successful in meeting our cash and credit requirements in 2001, no assurance can be provided that we will be able to obtain new financing to meet our obligations under our corporate credit facilities in 2001, or if we were able to obtain new financing, that the new financing would be on similar terms and rates as our existing credit facilities, on commercially reasonable terms or on the terms required by the Mission Energy Holding financing documents.

In addition to our obligation to reduce our credit facilities to $1 billion in the aggregate under the credit facilities, we are also required to use 50% of the net proceeds from the sale of assets and 100% of the net proceeds from our issuance of capital markets debt to repay senior bank indebtedness until

the aggregate commitment amount under our existing credit facilities is further reduced to $850 million. In this regard, we may incur additional federal and state income taxes from the proceeds of the sale of one of our foreign projects if the sale of this project is completed and we are required to repatriate funds to reduce senior bank indebtedness. There is no assurance that we will be able to sell projects on favorable terms or that the sale of individual projects will not result in a loss. We are also considering sale-leaseback transactions of certain projects, the proceeds of which would be used to repay short-term indebtedness or to meet other capital requirements.

The estimated capital expenditures of our subsidiaries for the second half of 2001 are $117 million, including environmental expenditures disclosed under "—Environmental Matters and Regulations." These capital expenditures are planned to be financed by existing subsidiary credit agreements and cash generated from their operations. Other than as described under "—Commitments and Contingencies," we do not plan to make additional capital contributions to our subsidiaries.

During the second quarter of 2001, we completed the purchase of additional shares of Contact Energy for NZ$152 million, thereby increasing our ownership interest from 42.6% to 51.2%. In order to finance this purchase, we obtained a NZ$135 million, 364-day bridge loan from an investment bank under a credit facility which is to be syndicated by the bank. In addition to other security arrangements, a security interest over all Contact Energy shares held has been provided as collateral. In June and July 2001, we issued through one of our subsidiaries new preferred securities to repay the bridge loan. On July 2, 2001, we redeemed NZ$400 million EME Taupo preferred securities from the existing holders. Funding for the redemption of the existing preferred securities was provided by a NZ$400 million credit facility scheduled to mature in July 2005. The financing documents governing the credit facility provide that the credit facility may be funded under either, or a combination of, a letter of credit facility or a revolving credit facility. The NZ$400 million was originally funded as a revolving credit facility.

The financial performance of the Fiddler's Ferry and Ferrybridge power plants has not met our expectations, largely due to lower energy power prices resulting primarily from increased competition, milder winter weather and uncertainty surrounding the new electricity trading arrangements. See "—Market Risk Exposures—United Kingdom." As a result, Edison First Power has defaulted on its financing documents related to the acquisition of the power plants. As a result of the reduced financial performance, Edison First Power deferred some environmental capital expenditure milestone requirements in the original capital expenditure program set forth in the financing documents. The original capital expenditure program has been revised, and this revision has been agreed to by the financing parties. In addition, in July 2001, the financing parties waived technical defaults under the financing documents and a default under the financing documents resulting from the fact that, due to this reduced financial performance, Edison First Power's debt service coverage ratio during 2000 declined below the threshold set forth in the financing documents. There is no assurance that Edison First Power's creditors will continue to waive its non-compliance with the requirements under the financing documents or that Edison First Power will satisfy its financial ratios in the future.

The financing documents stipulate that a breach of the financial ratio covenant constitutes an immediate event of default and, if the event of default is not waived, the financing parties are entitled to enforce their security over Edison First Power's assets, including the Fiddler's Ferry and Ferrybridge plants. Despite the breaches under the financing documents, Edison First Power's debt service coverage ratio for 2000 exceeded 1:1. Due to the timing of its cash flows and debt service payments, Edison First

Power utilized £37 million from its debt service reserve to meet its debt service requirements in 2000. In March 2001, £61 million was paid by Edison First Power to meet its semi-annual debt service requirements.

Another of our subsidiaries, EME Finance UK Limited, is the borrower under the facility made available for the purposes of funding coal and capital expenditures related to the Fiddler's Ferry and Ferrybridge power plants. At June 30, 2001, £58 million was outstanding for coal purchases and zero was outstanding to fund capital expenditures under this facility. EME Finance UK Limited on-lends any drawings under this facility to Edison First Power. The financing parties of this facility have also issued letters of credit directly to Edison First Power to support their obligations to lend to EME Finance UK Limited. EME Finance UK Limited's obligations under this facility are separate and apart from the obligations of Edison First Power under the financing documents related to the acquisition of these plants. We have guaranteed the obligations of EME Finance UK Limited under this facility, including any letters of credit issued to Edison First Power under the facility, for the amount of £359 million, and Edison Mission Energy's guarantee remains in force notwithstanding any breaches under Edison First Power's acquisition financing documents.

In accordance with SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed," we have evaluated impairment of the Ferrybridge and Fiddler's Ferry power plants. The undiscounted projected cash flow from these power plants exceeds the net book value at December 31, 2000, and, accordingly, no impairment of these power plants is permitted under SFAS No. 121. As a result of the change in the prices of power in the U.K., we are offering for sale through a competitive bidding process the Ferrybridge and Fiddler's Ferry power plants. Management has not made a decision whether or not the sale of these power plants will ultimately occur and, accordingly, these assets are not classified as held for sale. If we are successful at selling the Ferrybridge and Fiddler's Ferry plants, it is likely that we will not recover any of our investment in the subsidiary that owns these assets. At June 30, 2001, that investment was $974 million. We plan to use the proceeds from the sale, if it occurs, to repay a portion or all of the indebtedness of the project. There is no assurance that acceptable bids will be obtained or, if such bids are acceptable, that completion of the sale will occur. In this regard, there is no assurance that we will be able to negotiate acceptable terms and conditions with a potential buyer or that if an agreement was reached, that we will be able to satisfy the conditions needed for closing, which will include, among other things, a regulatory review in the United Kingdom.

Our subsidiary, Doga Enerji, owns 80% of the Doga project in Turkey. Doga Enerji has experienced delays in receiving payments from its power purchaser Turkiye Elektrik, A.S., also referred to as TEAS. Doga Enerji is in the process of determining whether these delays will materially adversely affect the future cash flow projections for the project. Until such determination is made, Doga Enerji will not make a distribution for 2001. While such payment obligations are guaranteed by the Turkish Treasury, we cannot assure you that TEAS will make its payments on a timely basis.

We participate in a tax sharing agreement with The Mission Group, which in turn participates in a tax sharing agreement with Edison International. We have historically received tax payments under the tax sharing agreement related to domestic net operating losses incurred by us. However, we will be required to pay Edison International $51 million during 2001 as a result of changes in estimated taxable income for 2000. At June 30, 2001, we have recorded $142.5 million as an income tax receivable under the tax sharing agreement. However, we are not eligible to receive tax sharing payments for such losses until such time as Edison International and its subsidiaries generate sufficient

taxable income in order to be able to monetize tax losses of Edison Mission Energy in the consolidated income tax returns for Edison International and its subsidiaries.

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

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

A downgrade in our credit ratings could increase our cost of capital, increase our credit support obligations, make efforts to raise capital more difficult and could have an adverse impact on us and 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 may not be available to satisfy our obligations or the obligations of any of our other subsidiaries. However, unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to us or to an affiliate of ours.

The following table summarizes our consolidated capital commitments as of June 30, 2001. Details regarding these capital commitments are discussed in the sections referenced.

Type of Commitment	Estimated Cost in U.S. $	Time Period	Discussed Under
	(in millions)
New Gas-Fired Generation	$250	by 2003	Illinois Plants—Power Purchase Agreements, included in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the year ended December 31, 2000
New Gas-Fired Generation	986*	2001-2004	Edison Mission Energy Master Turbine Lease, included in Item 7 of Edison Mission Energy's Annual Report on Form 10-K for the year ended December 31, 2000
Environmental Improvements at our Project Subsidiaries	494	2001-2005	Environmental Matters and Regulations
Project Acquisition for the Italian Wind Projects	8	2001-2002	Firm Commitment for Asset Purchase
Equity Contribution for the Sunrise Project	123	2001-2003	Firm Commitments to Contribute Project Equity
Equity Contribution for the Italian Wind Projects	1	2001-2002	Firm Commitments to Contribute Project Equity
Equity Contribution for the CBK Project	59	2003	Firm Commitments to Contribute Project Equity

Project		Local Currency		U.S. Currency
				(in millions)
Italian Wind Projects(i)		18 billion Italian Lira		$	7.9

Projects	Local Currency	U.S. Currency
		(in millions)
Italian Wind Projects(i)	3 billion Italian Lira	$	1.4
CBK Project(ii)	—		58.5
Sunrise Project(iii)	—		122.9

Edison Mission Energy has guaranteed to the bondholders, banks and other secured parties that financed the acquisition of the Homer City plant the performance and payment when due by Edison Mission Holdings Co. of its obligations in respect of specified senior debt, up to $42 million. This guarantee will be available until December 31, 2001, after which time Edison Mission Energy will have no further obligations under this guarantee. To satisfy the requirements under the Edison Mission Holdings Co. bank financing to have a debt service reserve account balance in an amount equal to six months' debt service, Edison Mission Energy provides a guarantee of Edison Mission Holdings' obligations in the amount of $9 million to the lenders involved in the bank financing.

financial information, additional guarantees, collateral, letters of credit or cash. Failure to provide adequate assurance could result in a counterparty liquidating an open position and filing a claim against Edison Mission Marketing & Trading for any losses.

energy delivered to PT PLN from the plant during this period. PT PLN made all fixed payments due under the Phase I Agreement totaling $108 million as scheduled. Paiton Energy received lender approval of the Phase I Agreement, and Paiton Energy has also entered into a lender interim agreement under which lenders have effectively agreed to interest-only payments and to deferral of principal payments while Paiton Energy and PT PLN seek a long-term restructuring of the tariff. The lenders have agreed to extend that agreement through December 31, 2001. Paiton Energy and PT PLN intended to complete the negotiations of the future phases of a new long-term tariff during the six-month duration of the Phase I Agreement. Although Paiton Energy and PT PLN did not complete negotiations on a long-term restructuring of the tariff by June 30, 2001, Paiton Energy and PT PLN have signed an agreement providing for an extension of the Phase I Agreement from July 1, 2001 to September 30, 2001. Paiton Energy is continuing to generate electricity to meet the power demand in the region and believes that PT PLN will continue to agree to make payments for electricity on an interim basis beyond June 30, 2001 while negotiations regarding the long-term restructuring of the tariff continue. Although completion of negotiations may be delayed, Paiton Energy continues to believe that negotiations on the long-term restructuring of the tariff will be successful. For a more detailed discussion of the restructuring of the tariff and related matters, refer to "Commitments and Contingencies—Paiton" in Item 7. of Edison Mission Energy's Annual Report on Form 10-K for the fiscal year ended December 31, 2000.

Projects	Local Currency	U.S. Currency
		(in millions)
Paiton(i)	—	$	5.3
ISAB(ii)	84 billion Italian Lira		36.5

We are not aware of any other significant contingent obligations or obligations to contribute project equity other than as noted above and equity contributions to be made by us to meet capital calls by partnerships who own qualifying facilities that have power purchase agreements with Southern California Edison and Pacific Gas and Electric. See "—The California Power Crisis and Our Response" for further discussion.

We have partnership interests in eight partnerships that own power plants in California and have power purchase contracts with Pacific Gas and Electric and/or Southern California Edison. Three of these partnerships have a contract with Southern California Edison, four of them have a contract with Pacific Gas and Electric, and one of them has contracts with both. In 2000, our share of earnings before taxes from these partnerships was $168 million, which represented 20% of our operating income. Our investment in these partnerships at June 30, 2001 was $607 million.

As a result of Southern California Edison's and Pacific Gas and Electric's current liquidity crisis, each of these utilities has failed to make payments to qualifying facilities supplying them power. These qualifying facilities include the eight power plants that are owned by partnerships in which we have a partnership interest. Southern California Edison has not paid a substantial majority of the amount due to the partnerships for power delivered between November 1, 2000 and March 26, 2001; however, in response to the March 27, 2001 California Public Utilities Commission order discussed below, Southern California Edison has been paying the partnerships for power delivered after March 27, 2001. It is possible that Southern California Edison may miss future payments. At June 30, 2001, accounts receivable due to these partnerships from Southern California Edison were $606 million. Our share of these receivables was $301 million.

On April 6, 2001, Pacific Gas and Electric filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code in San Francisco bankruptcy court. Pacific Gas and Electric made its January payment in full and has paid for power delivered after April 6, 2001, but paid only a small portion of the amounts due to the partnerships in February and March and, as discussed below, may not pay all or a portion of its future payments. Although Pacific Gas and Electric has thus far paid for post-petition deliveries, future payments by Pacific Gas and Electric to the qualifying facilities, including those owned by partnerships in which we have a partnership interest, may be subject to significant delays associated with the bankruptcy court process and may not be paid in full. Furthermore, Pacific Gas and Electric's power purchase agreements with the qualifying facilities will be subject to review by the bankruptcy court. At the petition date, accounts receivable to these partnerships from Pacific Gas and Electric were $47 million. Our share of these receivables was $23 million. We cannot assure you that the partnerships with long-term contracts with Pacific Gas and Electric will not be adversely affected by the bankruptcy proceeding.

The California utilities' failure to pay has adversely affected the operations of our eight California qualifying facilities. Continuing failures to pay similarly could have an adverse impact on the operations of our California qualifying facilities. Provisions in the partnership agreements stipulate that partnership actions concerning contracts with affiliates are to be taken through the non-affiliated partner in the partnership. Therefore, partnership actions concerning the enforcement of rights under each qualifying facility's power purchase agreement with Southern California Edison in response to Southern California Edison's suspension of payments under that power purchase agreement are to be taken through the non-Edison Mission Energy affiliated partner in the partnership. During the period in which Southern California Edison failed to make payments, some of the partnerships sought to minimize their exposure to Southern California Edison by reducing deliveries under their power purchase agreements. Four of the partnerships have filed complaints against Southern California Edison with respect to the payment defaults.

All of those partnerships have entered into agreements with Southern California Edison, under which the partnerships and Southern California Edison will suspend the current litigation for a specified "standstill period" and provisionally stipulate as to the amount of past due payments, and Southern California Edison will make partial payments with respect to past due amounts. The partial payments are to be made on the following schedule: 10% of the past due amount to be paid within three business days after signing the agreements, a second 10% to be paid upon the effective date of legislation that restores Southern California Edison to creditworthiness and enables it to pay its debts in a timely manner, and the final 80% on the fifth business day after the first day on which Southern California Edison receives proceeds from the first financing of the "net undercollected amount" resulting from such legislation. The agreements also require Southern California Edison to make monthly interest payments on past due amounts.

It is unclear at this time what additional actions, if any, the partnerships will take in regard to any future suspension of payments due to the qualifying facilities by the utilities or in the event that the settlement agreements cease to be in effect. As a result of the utilities' failure to make payments due under these power purchase agreements, the partnerships have called on the partners to provide additional capital to fund operating costs of the power plants. From January 1, 2001 to June 30, 2001, subsidiaries of ours have made equity contributions totaling approximately $134 million to meet capital calls by the partnerships. Although Southern California Edison has been paying the partnerships for power delivered after March 27, 2001 and Pacific Gas and Electric has paid for power delivered after April 6, 2001, our subsidiaries and the other partners may be required to make additional capital contributions to the partnerships if the utilities fail to make future payments.

Southern California Edison has stated that it is attempting to avoid bankruptcy and, subject to the outcome of regulatory and legal proceedings and negotiations regarding purchased power costs, it intends to pay all its obligations once a permanent solution to the current energy and liquidity crisis has been reached. However, it is possible that Southern California Edison will not pay all its obligations in full. In addition, it is possible that creditors of Southern California Edison could file an involuntary bankruptcy petition against Southern California Edison. If this were to occur, payments to the qualifying facilities, including those owned by partnerships in which we have a partnership interest, could be subject to significant delays associated with the lengthy bankruptcy court process and may not be paid in full. Furthermore, Southern California Edison's power purchase agreements with the qualifying facilities could be subject to review by a bankruptcy court.

While we believe that the generation of electricity by the qualifying facilities, including those owned by partnerships in which we have a partnership interest, is needed to meet California's power needs, we cannot assure you that these settlement agreements will continue to be effective during the standstill period, or that the power purchase agreements will not be adversely affected by a bankruptcy or any further contract renegotiation as a result of the current power crisis.

On March 27, 2001, the California Public Utilities Commission issued a decision that ordered the three California investor-owned utilities, including Southern California Edison and Pacific Gas and Electric, to commence payment for power generated from qualifying facilities beginning in April 2001. As a result of this decision, Southern California Edison paid in full for power delivered after March 27, 2001, and Pacific Gas and Electric paid for power delivered after April 6, 2001 (the date it filed its bankruptcy petition). This decision did not address payment to the qualifying facilities for amounts due prior to March 27, 2001. In addition, the decision modified the pricing formula for determining short-run avoided costs for qualifying facilities subject to these provisions. Depending on the utilities' continued reaction to this order, the impact of this decision may be that the qualifying facilities subject to this pricing adjustment will be paid at significantly reduced prices for their power. Furthermore, this decision called for further study of the pricing formula tied to short-run avoided costs and, accordingly, may be subject to more changes in the future. Finally, this decision is subject to challenge before the Commission, the Federal Energy Regulatory Commission and, potentially, state or federal courts. Although it is premature to assess the full effect of this decision, it could have a material adverse effect on our investment in the California partnerships, depending on how it is implemented and future changes in the relationship between the pricing formula and the actual cost of natural gas procured by our California partnerships.

As previously disclosed by Edison International, on April 9, 2001, Edison International and Southern California Edison signed a Memorandum of Understanding with the California Department of Water Resources. The Memorandum calls for legislation, regulatory action and definitive agreements to resolve important aspects of the energy crisis, and which the parties expect will help restore Southern California Edison's creditworthiness and liquidity. Edison International filed a Form 8-K on April 10, 2001, which describes key elements of the Memorandum. Among other things, the Memorandum provides that we will execute a contract with the Department of Water Resources or another state agency for the provision of power from the Sunrise project to the State at cost-based rates for ten years. We executed this contract on June 25, 2001, and the first phase became operational on June 27, 2001.

Edison International and Southern California Edison believe that execution of the Memorandum was an important step toward an acceptable resolution of the major issues affecting Edison International and Southern California Edison as a result of the California energy crisis, but this result is not assured. The parties agreed in the Memorandum that each of its elements is part of an integrated package, and effectuation of each element will depend upon effectuation of the others. To implement the Memorandum, numerous actions must be taken by the parties and by other agencies of the State of California. Southern California Edison, Edison International and the Department of Water Resources committed to proceed in good faith to sponsor and support the required legislation and to negotiate in good faith the necessary definitive agreements. However, the California Legislature, the California Public Utilities Commission, the Federal Energy Regulatory Commission, and other governmental entities on whose part action will be necessary to implement the Memorandum are not parties to the Memorandum. Furthermore, the Memorandum may be terminated by either Southern California Edison or the California Department of Water Resources at any time because required regulatory actions were not taken before the applicable deadline, but neither party has terminated the Memorandum. It is unlikely that the required legislation will be enacted before the applicable deadline. Further action on a solution to Southern California Edison's financial crisis is not expected before August 20, 2001, when the California Legislature returns from its summer recess. A number of alternatives to the Memorandum have been proposed in the California Legislature, some of which would not be effective in restoring the creditworthiness of Southern California Edison. Whether the Memorandum or any acceptable alternative to the Memorandum will be enacted is unknown. In addition, a California voter initiative or referendum previously has been threatened against any measures that would raise consumer rates or aid California's investor-owned utilities. Finally, execution

of the Memorandum does not eliminate the possibility that some of Southern California Edison's creditors could take steps to force Southern California Edison into bankruptcy proceedings.

On April 3, 2001, the California Public Utilities Commission adopted an order instituting investigation. The order reopens past Commission decisions authorizing the California investor-owned utilities to form holding companies and initiates an investigation into: whether the holding companies violated requirements to give priority to the capital needs of their respective utility subsidiaries; whether ring-fencing actions by Edison International and PG&E Corporation and their respective non-utility affiliates (including us) also violated requirements to give priority to the capital needs of their utility subsidiaries; whether the payment of dividends by the utilities violated requirements that the utilities maintain dividend policies as though they were comparable stand-alone utility companies; any additional suspected violations of laws or Commission rules and decisions; and whether additional rules, conditions, or other changes to the holding company decisions are necessary. The Memorandum calls for the Commission to adopt a decision clarifying that the first priority condition in Southern California Edison's holding company decision refers to equity investment, not working capital for operating costs. On June 6, 2001, in response to motions filed by the three holding companies (including Edison International) to dismiss the investigation for lack of subject matter jurisdiction, the Commission issued for comment a draft decision, which concludes, among other matters, that applicable law permits the Commission, even if the normal common law prerequisites for piercing the corporate structures are absent, to disregard the corporate forms within the holding company system "to reach the assets of or challenge the behaviors of entities within the holding company system" in order to protect ratepayers. Commissioner Henry Duque has issued a draft alternate decision that would grant the three holding companies' motions to dismiss the order as to themselves, finding lack of subject matter jurisdiction over them, and would direct the Commission's general counsel to file an action in state court to enforce the holding company conditions, if necessary. The alternate, as well as the draft decision that would deny the motions to dismiss, are presently on the Commission's agenda for its August 23 meeting. Either would require a vote of three out of five commissioners in order to be adopted. We are not a party to this investigatory proceeding. We cannot predict whether, when or in what form this order will be adopted, or what direct or indirect effects any subsequent action taken by the Commission in such proceeding or in any other action or proceeding, in reliance on the principles articulated in this order and in other applicable authority, may have on Edison International or on us and our subsidiaries.

A number of federal and state, legislative and regulatory initiatives addressing the issues of the California electric power industry have been proposed, including wholesale rate caps, retail rate increases, acceleration of power plant permitting and state entry into the power market. Many of these activities are ongoing. For example, on March 27, 2001, the California Public Utilities Commission made permanent the interim surcharge on customers' bills that it authorized on January 4, 2001 and authorized a rate increase of three cents per kilowatt-hour; neither this interim surcharge nor the rate increase affected the retail rate freeze which has been in effect since deregulation began in 1998. On April 26, 2001, the Federal Energy Regulatory Commission ordered price mitigation measures, or price caps, for power sales in the California spot market during emergency periods only; on June 19, 2001, the price mitigation measures were expanded to apply during all periods and to cover the entire eleven-state Western region. After extensive settlement negotiations failed to produce a global settlement, on July 25, 2001 the Federal Energy Regulatory Commission ordered that refunds may be due from sellers who engaged in transactions in these markets from October 2, 2000 through June 20, 2001, at levels in excess of the requirements in the April 26 and July 19 orders (with certain modifications), and ordered an evidentiary hearing to determine the required refunds. A separate proceeding was also instituted to evaluate the potential for refunds in the Pacific Northwest. The price mitigation measures end on September 30, 2002. The federal and state, legislative and regulatory initiatives may result in a restructuring of the California power market. At this time, it is not possible to estimate the likely ultimate outcome of these activities.

To isolate ourselves from the credit downgrades and potential bankruptcies of 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 in spite of the current credit difficulties of Edison International, Southern California Edison and their subsidiaries. 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:

We cannot assure you that these measures will effectively isolate us from the credit downgrades or the potential bankruptcies of Edison International, Southern California Edison or any of their subsidiaries. In January 2001, after we implemented the ring-fencing amendments, Standard & Poor's and Moody's lowered our credit ratings. Our senior unsecured credit ratings were downgraded to "BBB-" from "A-" by Standard & Poor's and to "Baa3" from "Baa1" by Moody's. Our credit ratings remain investment grade. Both Standard & Poor's and Moody's have indicated that the credit ratings outlook for us is stable. However, as a result of the downgrades, our cost of capital has increased. Future downgrades could further increase our cost of capital, increase our credit support obligations, make efforts to raise capital more difficult and could have an adverse impact on us and our subsidiaries. The measures described above are intended to insure that we are considered a stand-alone entity. However, in the event of a bankruptcy of Mission Energy Holding, creditors of Mission Energy Holding might seek to have a bankruptcy court substantially consolidate the assets and liabilities of us with those of Mission Energy Holding.

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.

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 plant, to the Pennsylvania-New Jersey-Maryland Power Pool (PJM) or the New York Independent System Operator (NYISO). We have developed risk management policies and procedures, which, among other things, address credit risk. When making sales under negotiated bilateral contracts, it is our policy to deal with investment grade counterparties or counterparties that provide equivalent credit support. Our Risk Management Committee grants exceptions to the policy only after thorough review and scrutiny. Most entities that have received exceptions are organized power pools and quasi-governmental agencies. We hedge a portion of the electric output of our merchant plants, whose output is not committed to be sold under long-term contracts, in order to lock in desirable outcomes. 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.

On September 1, 2000, we acquired the trading operations of Citizens Power LLC. As a result of this acquisition, we have expanded our trading operations beyond the traditional marketing of our electric power. Our energy trading and price risk management activities give rise to market risk, which represents the potential loss that can be caused by a change in the market value of a particular commitment. Market risks are actively monitored to ensure compliance with our risk management policies. Policies are in place that limit the amount of total net exposure we may enter into at any point in time. Procedures exist that 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 reasons for 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 industry "best practice" techniques including the use of stress testing and worst-case scenario analysis, as well as stop limits and counterparty credit exposure limits.

Electric power generated at the Homer City plant 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 plant is situated in the PJM control area and is physically connected to high-voltage transmission lines serving both the PJM and NYISO markets. The Homer City plant can also transmit power to the Midwestern United States.

Electric power generated at the Illinois Plants is sold under three power purchase agreements with Exelon Generation Company, in which Exelon Generation purchases capacity and has the right to purchase energy generated by the Illinois Plants. The agreements, which began on December 15, 1999 and have a term of up to five years, provide for capacity and energy payments. Exelon Generation is obligated to make a capacity payment for the plants under contract and an energy payment for the electricity produced by these plants and taken by Exelon Generation. The capacity payments provide the Illinois Plants revenue for fixed charges, and the energy payments compensate the Illinois Plants for variable costs of production. Exelon Generation has the option to terminate two of the three agreements in their entirety or with respect to any generating unit or units in each of 2002, 2003 and 2004. In June 2001, Exelon Generation provided us notice to continue the agreement related to the coal units for 2002. If Exelon Generation does not fully dispatch the plants under contract, the Illinois Plants may sell, subject to specified conditions, the excess energy at market prices to neighboring utilities, municipalities, third-party electric retailers, large consumers and power marketers on a spot

basis. A bilateral trading infrastructure already exists with access to the Mid-America Interconnected Network and the East Central Area Reliability Council.

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 with a bilateral physical trading system referred to as the new electricity trading arrangements.

The new electricity trading arrangements provide for, among other things, the establishment of a spot market or voluntary short-term power exchanges operating from a year or more in advance to 3¹/2-hours before a trading period of ¹/2 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. Contracting over time periods longer than the day-ahead market is not directly affected by the proposals. Physical bilateral contracts have replaced the prior financial contracts for differences, but function in a similar manner. However, it remains difficult to evaluate the future impact of the new electricity trading arrangement. 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, against their contracted positions or face assessment of energy imbalance penalty charges by the system operator. A consequence of this should be to increase greatly the motivation of parties to contract in advance and develop forwards and futures markets of greater liquidity than at present. Recent experience has been that the new electricity trading arrangements have placed a significant downward pressure on forward contract prices. Furthermore, another consequence may be that counterparties may require additional credit support, including parent company guarantees or letters of credit. Legislation in the form of the Utilities Act, which was approved July 28, 2000, provided for the implementation of the new electricity trading arrangements and the necessary amendments to generators' licenses.

The legislation providing for the implementation of the new arrangements, the Utilities Act 2000, sets 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. But this is qualified by a recognition that license holders should be able to finance their activities. The Act 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 will be monitoring the operation of these new provisions. See "—Liquidity and Capital Resources."

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

Hedge. Additionally, the Loy Yang B plant entered into a number of fixed forward electricity contracts commencing either in 2001 or 2002, which expire on various dates through December 31, 2002, and which will further mitigate against the price volatility of the electricity pool.

New Zealand. The New Zealand Government has been undergoing a steady process of electric industry deregulation since 1987. Reform in the distribution and retail supply sector began in 1992 with legislation that deregulated electricity distribution and provided for competition in the retail electric supply function. The New Zealand Energy Market, established in 1996, is a voluntary competitive wholesale market that allows for the trading of physical electricity on a half-hourly basis. The Electricity Industry Reform Act, which was passed in July 1998, was designed to increase competition at the wholesale generation level by splitting up Electricity Company of New Zealand Limited, the large state- owned generator, into three separate generation companies. The Electricity Industry Reform Act also prohibits the ownership of both generation and distribution assets by the same entity.

The New Zealand Government commissioned an inquiry into the electricity industry in February 2000. This Inquiry Board's report was presented to the government in mid 2000. The main focus of the report was on the monopoly segments of the industry, transmission and distribution, with substantial limitations being recommended in the way in which these segments price their services in order to limit their monopoly power. Recommendations were also made with respect to the retail customer in order to reduce barriers to customers switching. In addition, the Board made recommendations in relation to the wholesale market's governance arrangements with the purpose of streamlining them. The recommended changes are now being progressively implemented.

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 or other hedging mechanisms for a number of our project financings. Interest expense included $9.3 million and $9.6 million of additional interest expense for the six months ended June 30, 2001 and 2000, 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 $819.8 million consisting of commercial paper and bank borrowings at June 30, 2001. The fair values of these obligations approximated their carrying values at June 30, 2001, and would not have been materially affected by changes in market interest rates. The fair market value 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 $7.7 billion at June 30, 2001.

Fluctuations in foreign currency exchange rates can affect, on a United States dollar equivalent basis, the amount of our equity contributions to, and distributions from, our international projects. As we continue to expand into foreign markets, fluctuations in foreign currency exchange rates can be expected to have a greater impact on our results of operations in the future. 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 United States dollars or other indices reasonably expected to correlate with foreign exchange movements. In addition, we have used statistical forecasting techniques to help assess foreign exchange risk and the probabilities of various outcomes. We cannot assure you, however, that fluctuations in exchange rates will be fully offset by hedges or that currency movements and the relationship between certain macro economic variables will behave in a manner that is consistent with historical or

forecasted relationships. Foreign exchange considerations for three major international projects, other than Paiton, which was discussed earlier, are discussed below.

The First Hydro, Ferrybridge and Fiddler's Ferry plants in the U.K. and the Loy Yang B plant in Australia have been financed in their local currency, 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.

Foreign currencies in the U.K., Australia and New Zealand decreased in value compared to the U.S. dollar by 6%, 8% and 9%, respectively (determined by the change in the exchange rates from December 31, 2000 to June 30, 2001). The decrease in value of these currencies was the primary reason for the foreign currency translation loss of $101.2 million during the first six months of 2001.

In December 2000, we entered into foreign currency forward exchange contracts in the ordinary course of business to protect ourselves from adverse currency rate fluctuations on anticipated foreign currency commitments. The periods of the forward exchange contracts correspond to the periods of the hedged transactions. At June 30, 2001, the outstanding notional amount of the contracts totaled $73 million, consisting of contracts to exchange U.S. dollars to pound sterling with varying maturities ranging from July 2001 to July 2002. During the first six months of 2001, we recognized a foreign exchange gain of approximately $36,000 related to the fuel purchases underlying the contracts that matured during the first six months of 2001.

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

The electric power generated by some of our investments in domestic operating projects, excluding the Homer City plant and the Illinois Plants, is sold to electric utilities under long-term contracts, typically with terms of 15 to 30 years. We structure our long-term contracts so that fluctuations in fuel costs will produce similar fluctuations in electric and/or steam revenues and enter into long-term fuel supply and transportation agreements. The degree of linkage between these revenues and expenses varies from project to project, but generally permits the projects to operate profitably under a wide array of potential price fluctuation scenarios.

We are subject to environmental regulation by federal, state and local authorities in the United States and foreign regulatory authorities with jurisdiction over projects located outside the United States. We believe that we are in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect our financial position or results of operation. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, and future proceedings that may be taken by environmental authorities, could affect the costs and the manner in which we conduct our business and could cause us to make substantial additional capital expenditures. There is no assurance that we would be able to recover these increased costs from our customers or that our financial position and results of operations would not be materially adversely affected.

Typically, environmental laws require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction and operation of a project. Meeting all the necessary requirements

can delay or sometimes prevent the completion of a proposed project as well as require extensive modifications to existing projects, which may involve significant capital expenditures.

We expect that compliance with the Clean Air Act and the regulations and revised State Implementation Plans developed as a consequence of the Act will result in increased capital expenditures and operating expenses. For example, we expect to spend approximately $34 million for the final two quarters of 2001 and $12 million in 2002 to install upgrades to the environmental controls at the Homer City plant to control sulfur dioxide and nitrogen oxide emissions. Similarly, we anticipate upgrades to the environmental controls at the Illinois Plants to control nitrogen oxide emissions to result in expenditures of approximately $22 million for the final two quarters of 2001 and $386 million for the 2002-2005 period. In addition, at the Ferrybridge and Fiddler's Ferry plants we anticipate environmental costs arising from plant modification of approximately $18 million for the final two quarters of 2001 and $21 million for the 2002-2005 period.

We own an indirect 50% interest in EcoEléctrica, L.P., a limited partnership, which owns and operates a liquefied natural gas import terminal and cogeneration project at Peñuelas, Puerto Rico. In 2000, the U.S. Environmental Protection Agency issued to EcoEléctrica a notice of violation and a compliance order alleging violations of the federal Clean Air Act primarily related to start-up activities. Representatives of EcoEléctrica have met with the Environmental Protection Agency to discuss the notice of violations and compliance order. To date, EcoEléctrica has not been informed of the commencement of any formal enforcement proceedings. It is premature to assess what, if any, action will be taken by the Environmental Protection Agency.

On November 3, 1999, the United States Department of Justice filed suit against a number of electric utilities for alleged violations of the Clean Air Act's "new source review" requirements related to modifications of air emissions sources at electric generating stations located in the southern and midwestern regions of the United States. Several states have joined these lawsuits. In addition, the United States Environmental Protection Agency has also issued administrative notices of violation alleging similar violations at additional power plants owned by some of the same utilities named as defendants in the Department of Justice lawsuit, as well as other utilities, and also issued an administrative order to the Tennessee Valley Authority for similar violations at certain of its power plants. The Environmental Protection Agency has also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities, including the prior owners of the Homer City plant, seeking to determine whether these utilities also engaged in activities that may have been in violation of the Clean Air Act's new source review requirements.

To date, one utility, the Tampa Electric Company, has reached a formal agreement with the United States to resolve alleged new source review violations. Two other utilities, the Virginia Electric & Power Company and Cinergy Corp., have reached agreements in principle with the Environmental Protection Agency. In each case, the settling party has agreed to incur over $1 billion in expenditures over several years for the installation of additional pollution control, the retirement or repowering of coal-fired generating units, supplemental environmental projects and civil penalties. These agreements provide for a phased approach to achieving required emission reductions over the next 10 to 15 years. The settling utilities have also agreed to pay civil penalties ranging from $3.5 million to $8.5 million.

Prior to our purchase of the Homer City plant, the Environmental Protection Agency requested information from the prior owners of the plant concerning physical changes at the plant. Other than with respect to the Homer City plant, no proceedings have been initiated or requests for information issued with respect to any of our United States facilities. However, we have been in informal voluntary discussions with the Environmental Protection Agency relating to these facilities, which may result in the payment of civil fines. We cannot assure you that we will reach a satisfactory agreement or that these facilities will not be subject to proceedings in the future. Depending on the outcome of the proceedings, we could be required to invest in additional pollution control requirements, over and

above the upgrades we are planning to install, and could be subject to fines and penalties. In May 2001, President Bush issued a directive for a 90-day review of new source review "interpretation and implementation" by the Administrator of the Environmental Protection Agency and the Secretary of the U.S. Department of Energy. President Bush also directed the Attorney General to review ongoing new source review legal actions to "ensure" they are "consistent with the Clean Air Act and its regulations." Both actions were recommendations detailed within the Bush Administration's "National Energy Policy Task Force Report."

A new ambient air quality standard was adopted by the Environmental Protection Agency in July 1997 to address emissions of fine particulate matter. It is widely understood that attainment of the fine particulate matter standard may require reductions in nitrogen oxides and sulfur dioxides, although under the time schedule announced by the Environmental Protection Agency when the new standard was adopted, non-attainment areas were not to have been designated until 2002 and control measures to meet the standard were not to have been identified until 2005. In May 1999, the United States Court of Appeals for the District of Columbia Circuit held that Section 109(b)(1) of the Clean Air Act, the section of the Clean Air Act requiring the promulgation of national ambient air quality standards, as interpreted by the Environmental Protection Agency, was an unconstitutional delegation of legislative power. The Court of Appeals remanded both the fine particulate matter standard and the revised ozone standard to allow the EPA to determine whether it could articulate a constitutional application of Section 109(b)(1). On February 27, 2001, the Supreme Court, in Whitman v. American Trucking Associations, Inc., reversed the Circuit Court's judgment on this issue and remanded the case back to the Court of Appeals to dispose of any other preserved challenges to the particulate matter and ozone standards. Accordingly, as the final application of the revised particulate matter ambient air quality standard is potentially subject to further judicial proceedings, the impact of this standard on our facilities is uncertain at this time.

On December 20, 2000, the Environmental Protection Agency issued a regulatory finding that it is "necessary and appropriate" to regulate emissions of mercury and other hazardous air pollutants from coal-fired power plants. The agency has added coal-fired power plants to the list of source categories under Section 112(c) of the Clean Air Act for which "maximum available control technology" standards will be developed. Eventually, unless overturned or reconsidered, the Environmental Protection Agency will issue technology-based standards that will apply to every coal-fired unit owned by us or our affiliates in the United States. This section of the Clean Air Act provides only for technology-based standards, and does not permit market trading options. Until the standards are actually promulgated, the potential cost of these control technologies cannot be estimated, and we cannot evaluate the potential impact on the operations of our facilities.

In June 2001, Illinois passed legislation mandating the Illinois Environmental Protection Agency to evaluate and issue a report to the Illinois legislature addressing the need for further emissions controls on fossil fuel-fired electric generating stations, including the potential need for additional controls on nitrogen oxides, sulfur dioxide and mercury. The study, which is to be submitted between September 30, 2003 and September 30, 2004, also requires an evaluation of incentives to promote renewable energy and the establishment of a banking system for certifying credits from voluntary reductions of greenhouse gases. The law allows the Illinois Environmental Protection Agency to propose regulations based on its findings no sooner than ninety days after the issuance of its findings, and requires the Illinois Pollution Control Board to act within one year on such proposed regulations. Until the Illinois Environmental Protection Agency issues its findings and proposes regulations in accordance with the findings, if such regulations are proposed, we cannot evaluate the potential impact of this legislation on the operations of our facilities.

Since the adoption of the United Nations Framework Convention on Climate Change in 1992, there has been worldwide attention with respect to greenhouse gas emissions. In December 1997, the Clinton Administration participated in the Kyoto, Japan negotiations, where the basis of a Climate

Change treaty was formulated. Under the treaty, known as the Kyoto Protocol, the United States would be required, by 2008-2012, to reduce its greenhouse gas emissions by 7% from 1990 levels.

The Kyoto Protocol has yet to be submitted to the U.S. Senate for ratification. In March 2001, the Bush Administration announced that the United States would not ratify the Kyoto Protocol, but would instead offer an alternative. Various bills have been, and are expected to be, introduced in Congress to address some of these implementing guidelines and other aspects of climate change. Apart from the Kyoto Protocol, we may be impacted by future federal or state legislation relating to controlling greenhouse gas emissions.

Notwithstanding the Bush Administration position, in July 2001, environment ministers from around the world met in Bonn, Germany and reached a compromise agreement on the mechanics and rules of the Kyoto Protocol. The compromise agreement is believed to clear the way for countries to begin the treaty ratification process. The United States was the sole country not to embrace the agreement.

We either have an equity interest in or own and operate generating plants in the following countries:

• Australia		• Spain
• Indonesia		• Thailand
• Italy		• Turkey
• New Zealand		• The United Kingdom
• Philippines		• The United States

With the exception of Turkey, all of the countries identified have ratified the UN Framework Convention on Climate Change, as well as signed the Kyoto Protocol. None of the countries have ratified the Kyoto Protocol, but, with the exception of the United States, all are expected to do so by the end of 2002. For the treaty to come into effect, it must be ratified by approximately 55 countries, representing at least 55% of the greenhouse gas emissions of the developed world.

All of the countries, with the exception of Indonesia, the Philippines and Thailand, are classified as Annex 1 or "developed" countries and are subject to national greenhouse gas emission reduction targets during the period of 2008-2012 (e.g., Phase 1). Each nation is actively developing policies and measures meant to assist it with meeting the individual national emission targets as set out within the Kyoto Protocol.

If we do become subject to limitations on emissions of carbon dioxide from our fossil fuel-fired electric generating plants, these requirements could have a significant economic impact on their operations.

The Environmental Protection Agency proposed rules establishing standards for the location, design, construction and capacity of cooling water intake structures at new facilities, including steam electric power plants. Under the terms of a consent decree entered into by the U.S. District Court for the Southern District of New York in Riverkeeper, Inc. v. Whitman, these regulations must be adopted by November 9, 2001. The consent decree also requires the agency to propose similar regulations for existing facilities by February 28, 2002, and finalize those regulations by August 28, 2003. Until the final standards are promulgated, we cannot determine their impact on our facilities or estimate the potential cost of compliance.

The Comprehensive Environmental Response, Compensation, and Liability Act, which is also known as CERCLA, and similar state statutes require the cleanup of sites from which there has been a release or threatened release of hazardous substances. As of the date of this report, we are unaware of any material liabilities under CERCLA or similar state statutes; however, we cannot assure you that we will not incur CERCLA liability or similar state law liability in the future.

In July 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets," which will be effective on January 1, 2002. The Statement 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.

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 or its recorded amount or incurs a gain or loss upon settlement.

For a complete discussion of market risk sensitive instruments, refer to "Market Risk Exposures" in Item 7. of Edison Mission Energy's Annual Report on Form 10-K for the fiscal year ended December 31, 2000. Refer to "Market Risk Exposures" in Item 2. for an update to that disclosure.

Exhibit No.		Description
3.1.3		Certificate of Amendment of Articles of Incorporation of Edison Mission Energy dated July 2, 2001.
10.15.2		Amendment Two to Second Amended and Restated U.S. $425 million Bank of America, N.A. Credit Agreement, dated as of May 30, 2001.
10.60.2		Amendment No. 2 to the Debt Service Reserve Guarantee, dated as of March 18, 2001, made by Edison Mission Energy in favor of United States Trust Company of New York.
10.61.2		Amendment Two to Credit Agreement, dated as of March 15, 2001, by and among Edison Mission Energy, certain commercial lending institutions, and Citicorp USA, Inc., as Administrative Agent.
10.61.3		Amendment Three to the U.S. $595 million Credit Agreement, dated as of May 30, 2001, by and among Edison Mission Energy, certain commercial lending institutions, and Citicorp USA, Inc., as Administrative Agent.
10.64.1		Amendment One to Coal and Capex Facility Agreement, dated as of May 29, 2001, by and among Edison Mission Energy Finance UK Limited and Barclays Bank PLC, as Facility Agent.
10.65.2		Amendment Two to Guarantee by Edison Mission Energy Supporting the Facility Agreement, dated as of May 29, 2001.
10.84.2		Amendment Two to the U.S. $255 million Credit Agreement, dated as of May 30, 2001, by and among Edison Mission Energy, Certain Commercial Lending Institutions and Bank of America, N.A. as Administrative Agent.
10.91		Supplemental Agreement, dated as of May 30, 2001, to Amendment Two to the Second Amended and Restated U.S. $425 million Bank of America, N.A. Credit Agreement dated as of May 30, 2001, Amendment Three to the U.S. $595 million Credit Agreement dated as of May 30, 2001 and Amendment Two to the U.S. $255 million Credit Agreement dated as of May 30, 2001.

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.

			Three Months Ended June 30,						Six Months Ended June 30,
			2001			2000			2001			2000
			(Unaudited)						(Unaudited)
Operating Revenues
	Electric revenues		$	677,347		$	687,476		$	1,342,566		$	1,378,790
	Equity in income from energy projects			104,871			47,100			169,061			76,403
	Equity in income from oil and gas investments			10,063			10,761			30,513			18,557
	Net gains (losses) from energy trading and price risk management			10,798			(32,040	)		19,835			(33,789	)
	Operation and maintenance services			12,589			9,931			23,842			20,190

		Total operating revenues		815,668			723,228			1,585,817			1,460,151

Operating Expenses
	Fuel			278,020			236,476			559,566			512,775
	Plant operations			246,793			214,419			459,107			402,381
	Operation and maintenance services			6,101			7,700			13,542			15,681
	Depreciation and amortization			88,709			99,500			174,320			202,495
	Long-term incentive compensation			823			—			(2,891	)		—
	Administrative and general			38,456			39,726			75,954			73,849

		Total operating expenses		658,902			597,821			1,279,598			1,207,181

	Operating income			156,766			125,407			306,219			252,970

Other Income (Expense)
	Interest and other income			16,251			16,482			31,020			25,537
	Gain on sale of assets			3,644			16,990			3,644			16,990
	Interest expense			(162,639	)		(181,176	)		(316,493	)		(354,147	)
	Dividends on preferred securities			(6,090	)		(8,253	)		(12,380	)		(16,360	)
	Minority interest			(7,009	)		(555	)		(7,522	)		(1,447	)

		Total other income (expense)		(155,843	)		(156,512	)		(301,731	)		(329,427	)

	Income (loss) before income taxes			923			(31,105	)		4,488			(76,457	)
	Provision (benefit) for income taxes			639			(12,581	)		1,738			(27,772	)

Income (Loss) Before Accounting Change				284			(18,524	)		2,750			(48,685	)
Cumulative effect on prior years of change in accounting for derivatives, net of tax				—			—			6,001			—
Cumulative effect on prior years of change in accounting for major maintenance costs, net of tax				—			—			—			17,690

Net Income (Loss)			$	284		$	(18,524	)	$	8,751		$	(30,995	)

			Three Months Ended June 30,						Six Months Ended June 30,
			2001			2000			2001			2000
			(Unaudited)						(Unaudited)
Net Income (Loss)			$	284		$	(18,524	)	$	8,751		$	(30,995	)
Other comprehensive income (expense), net of tax:
	Foreign currency translation adjustments, net of income tax benefit of $316 and $2,620 for the three months and $2,665 and $3,427 for the six months ended June 30, 2001 and 2000, respectively			(4,644	)		(94,738	)		(101,289	)		(138,271	)
	Unrealized gains (losses) on derivatives qualified as cash flow hedges:
		Cumulative unrealized holding losses upon adoption of a change in accounting principle, net of income tax benefit of $110.9 million		—			—			(230,239	)		—
		Other unrealized holding gains arising during period, net of income tax expense of $86.2 million and $68.8 million for the three months and six months ended June 30, 2001, respectively		120,199			—			81,488			—
		Add: reclassification adjustment for losses included in net income, net of income tax benefit of $2 million and $17.6 million for the three months and six months ended June 30, 2001, respectively		2,411			—			30,682			—

	Net unrealized gains (losses) on derivatives qualified as cash flow hedges			122,610			—			(118,069	)		—

Other comprehensive income (expense)				117,966			(94,738	)		(219,358	)		(138,271	)

Comprehensive Income (Loss)			$	118,250		$	(113,262	)	$	(210,607	)	$	(169,266	)

			June 30, 2001		December 31, 2000
			(Unaudited)
Assets
Current Assets
	Cash and cash equivalents		$	573,443	$	962,865
	Accounts receivable—trade, net of allowance of $404 in 2001 and $1,126 in 2000			582,998		506,936
	Accounts receivable—affiliates			153,735		156,862
	Assets under energy trading and price risk management			166,253		251,524
	Inventory			327,203		279,864
	Prepaid expenses and other			67,066		49,004

		Total current assets		1,870,698		2,207,055

Investments
	Energy projects			1,921,360		2,044,043
	Oil and gas			32,710		43,549

		Total investments		1,954,070		2,087,592

Property, Plant and Equipment				11,132,905		10,585,710
	Less accumulated depreciation and amortization			844,622		721,586

		Net property, plant and equipment		10,288,283		9,864,124

Other Assets
	Long-term receivables			268,179		267,599
	Goodwill			641,631		289,146
	Deferred financing costs			115,555		113,652
	Long-term assets under energy trading and price risk management			959		56,695
	Restricted cash and other			117,940		131,228

		Total other assets		1,144,264		858,320

Total Assets			$	15,257,315	$	15,017,091

			June 30, 2001			December 31, 2000
			(Unaudited)
Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable—affiliates		$	17,325		$	25,489
	Accounts payable and accrued liabilities			513,080			736,213
	Liabilities under energy trading and price risk management			125,463			281,657
	Interest payable			131,140			123,354
	Short-term obligations			819,787			883,389
	Current portion of long-term incentive compensation			10,557			93,000
	Current maturities of long-term obligations			1,413,803			1,767,898

		Total current liabilities		3,031,155			3,911,000

Long-Term Obligations Net of Current Maturities				6,349,278			5,334,789

Long-Term Deferred Liabilities
	Deferred taxes and tax credits			1,580,826			1,611,485
	Deferred revenue			422,885			460,481
	Long-term incentive compensation			40,672			51,766
	Long-term liabilities under energy trading and price risk management			185,192			58,016
	Other			305,299			296,594

		Total long-term deferred liabilities		2,534,874			2,478,342

Total Liabilities				11,915,307			11,724,131

Minority Interest				343,750			18,016

Preferred Securities of Subsidiaries
	Company-obligated mandatorily redeemable security of partnership holding solely parent debentures			150,000			150,000
	Subject to mandatory redemption			175,681			176,760

		Total preferred securities of subsidiaries		325,681			326,760

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			2,629,406			2,629,406
	Retained earnings			345,147			401,396
	Accumulated other comprehensive loss			(366,106	)		(146,748	)

Total Shareholder's Equity				2,672,577			2,948,184

Total Liabilities and Shareholder's Equity			$	15,257,315		$	15,017,091

			Six Months Ended June 30,
			2001			2000
			(Unaudited)
Cash Flows From Operating Activities
	Net income (loss)		$	8,751		$	(30,995	)
	Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
		Equity in income from energy projects		(169,061	)		(76,403	)
		Equity in income from oil and gas investments		(30,513	)		(18,557	)
		Distributions from energy projects		18,757			53,158
		Dividends from oil and gas investments		40,667			12,530
		Depreciation and amortization		174,320			202,495
		Deferred taxes and tax credits		(7,504	)		(71,213	)
		Amortization of discount on short-term obligations		1,106			38,117
		Gain on sale of assets		(3,644	)		(16,990	)
		Cumulative effect on prior years of change in accounting, net of tax		(6,001	)		(17,690	)
	(Increase) decrease in accounts receivable			8,131			(117,909	)
	Increase in inventory			(42,059	)		(62,633	)
	Decrease in prepaid expenses and other			6,218			6,703
	Increase (decrease) in accounts payable and accrued liabilities			(376,460	)		188,298
	Increase in interest payable			7,637			32,027
	Decrease in long-term incentive compensation			(8,077	)		(47,340	)
	Decrease in net assets under risk management			29,362			—
	Other, net			(23,762	)		(5,232	)

		Net cash provided by (used in) operating activities		(372,132	)		68,366

Cash Flows From Financing Activities
	Borrowings long-term obligations			1,761,342			2,351,066
	Payments on long-term obligations			(1,265,937	)		(1,858,207	)
	Short-term financing, net			(63,176	)		75,713
	Cash dividends to parent			(65,000	)		(44,000	)
	Issuance of preferred securities			14,161			—

		Net cash provided by financing activities		381,390			524,572

Cash Flows From Investing Activities
	Investments in and loans to energy projects			(290,917	)		(98,841	)
	Purchase of common stock of acquired companies			(83,381	)		(28,448	)
	Capital expenditures			(113,199	)		(178,504	)
	Proceeds from sale of interest in projects			110,853			22,000
	Decrease in restricted cash			12,842			3,571
	Other, net			16,339			(27,359	)

		Net cash used in investing activities		(347,463	)		(307,581	)

Effect of exchange rate changes on cash				(51,217	)		(33,277	)

Net increase (decrease) in cash and cash equivalents				(389,422	)		252,080
Cash and cash equivalents at beginning of period				962,865			398,695

Cash and cash equivalents at end of period			$	573,443		$	650,775

Three Months Ended	Americas		Asia Pacific		Europe, Central Asia, Middle East and Africa			Corporate/ Other			Total
	(Unaudited) (in millions)
June 30, 2001
Operating revenues	$	503.3	$	96.9	$	215.1		$	0.4		$	815.7
Operating income (loss)		152.3		45.4		(4.5	)		(36.4	)		156.8
Total assets	$	6,724.0	$	3,115.2	$	4,749.7		$	668.4		$	15,257.3
June 30, 2000
Operating revenues	$	419.7	$	42.5	$	261.0		$	—		$	723.2
Operating income (loss)		82.8		19.4		67.7			(44.5	)		125.4
Total assets	$	7,759.4	$	2,798.7	$	4,865.7		$	108.0		$	15,531.8