Prepared by MERRILL CORPORATION

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

California		95-4031807
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
18101 Von Karman Avenue Irvine, California		92612
(Address of principal executive offices)		(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 May 14, 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	19
3.	Quantitative and Qualitative Disclosures About Market Risk	42
PART II—Other Information
6.	Exhibits and Reports on Form 8-K	43
Signatures	44

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

All adjustments, including recurring accruals, have been made that are necessary to present fairly the consolidated financial position and results of operations for the periods covered by this report. The results of operations for the three months ended March 31, 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.

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 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 and others. Pacific Gas and Electric filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code on April 6, 2001. Given its payment defaults, creditors of Southern California Edison could file an involuntary bankruptcy petition against it. 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 our investments, see "—Note 6. Commitments and Contingencies—California Power Crisis."

Effective January 1, 2001, Edison Mission Energy adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." The Statement establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. 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. We did not use this exception for forward sales contracts from our Homer City plant due to our net settlement procedures with counterparties.

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 March 31, 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. In the quarter ended March 31, 2001, we recorded a loss of $7.1 million, after tax, as the change in the fair value of derivatives required under SFAS No. 133 that previously qualified for hedge accounting. We recorded a $6 million, after tax, increase to net income as a 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. We also recorded a net gain of $155,000 representing the amount of cash flow hedges' ineffectiveness during the quarter ended March 31, 2001, reflected in net gains (losses) from energy trading and price risk management in the consolidated income statement.

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 March 31, 2001 and December 31, 2000 consisted of the following:

	March 31, 2001		December 31, 2000
	(Unaudited)
	(in millions)
Coal and fuel oil	$	205.9	$	207.8
Spare parts, materials and supplies		66.8		72.1

Total	$	272.7	$	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		(96.6	)		(240.7	)		(337.3	)

Balance at March 31, 2001 (Unaudited)	$	(243.4	)	$	(240.7	)	$	(484.1	)

Unrealized gains (losses) on cash flow hedges at March 31, 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 95% of our accumulated other comprehensive loss at March 31, 2001 related to unrealized losses on cash flow hedges resulting from these contracts. These 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 these contracts continue to qualify as cash flow hedges, future changes in the forecast of market prices for contract volumes included in these agreements will increase or decrease our other comprehensive income without affecting our net income.

As the positions are realized, approximately $33 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 16 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 726 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric project located in the Philippines. Financing for this $460 million project has been completed with equity contributions 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 has been arranged for the remainder of the cost for this project.

The following table summarizes our consolidated capital commitments as of March 31, 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	396		2001-2003	Acquisition of Sunrise Project, 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	516		2001-2005	Environmental Matters and Regulations
Project Acquisition for the Italian Wind Projects	16		2001-2002	Firm Commitment for Asset Purchase
Equity Contribution for the Italian Wind Projects	3		2001-2002	Firm Commitments to Contribute Project Equity
Equity Contribution for the CBK Project	59		2003	Firm Commitments to Contribute Project Equity

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. For the three-month period ended March 31, 2001, our share of earnings before taxes from these partnerships was $42 million, which represented 28% of our operating income. Our investment in these partnerships at March 31, 2001 was $498 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 did not pay any amount due to the partnerships in January, February and March of 2001 and may continue to miss future payments. However, on April 17, 2001, Southern California Edison made payment to the partnerships for April deliveries and subsequently made a supplemental payment for power delivered between March 27, 2001 and March 31, 2001. 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 post-petition deliveries during April, 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. At March 31, 2001, accounts receivable due to these partnerships from Southern California Edison were $472 million. Our share of these receivables was $234 million.

Although Pacific Gas and Electric has paid for post-petition deliveries during April, 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 due 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 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. Some of the partnerships have sought to minimize their exposure to Southern California Edison by reducing deliveries under their power purchase agreements. Three of the partnerships have filed complaints requesting, among other things, a declaration that they are entitled to suspend delivery of capacity and energy to Southern California

Edison, and to resell such capacity and energy to other purchasers, so long as Southern California Edison does not pay amounts due under its power purchase agreement and until Southern California Edison establishes that it is creditworthy and able to make future payments when due.

It is unclear at this time what additional actions, if any, the partnerships will take in regard to the utilities' suspension of payments due to the qualifying facilities. 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. Since January 1, 2001, subsidiaries of ours have made equity contributions totaling approximately $134 million to meet capital calls by the partnerships. Our subsidiaries and the other partners may be required to make additional capital contributions to the partnerships.

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 either that these partnerships will continue to generate electricity without payment by the purchasing utility, or that the power purchase agreements will not be adversely affected by a bankruptcy or 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 between March 27, 2001 and April 30, 2001, and Pacific Gas and Electric paid for post-petition April deliveries (for the period between April 6, 2001 and April 30, 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 recent 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. This decision did not address payment to the qualifying facilities for amounts due prior to April 2001.

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, our power project currently under development, to the State at cost-based rates for ten years. Edison International agreed that we will use all commercially reasonable efforts to place the first phase of the project into service before the end of Summer 2001.

Edison International and Southern California Edison believe that the Memorandum is 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 if required legislation is not adopted and definitive agreements executed by August 15, 2001, or if the California Public Utilities Commission does not adopt the required implementing decisions within 60 days after the Memorandum was signed, or if specified other adverse changes occur. We cannot provide assurance that all the required legislation will be enacted, regulatory actions taken, and definitive agreements executed before the applicable deadlines. 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.

impact on the investigation of the Memorandum. Several parties, including Edison International, raised objections to the Commission's assertion of jurisdiction over utility holding companies. The Commission is expected to issue a further ruling concerning the scope and scheduling of the investigation and also to schedule a further prehearing conference. We cannot predict what the effects of any investigation or subsequent actions by the Commission may have on Edison International or indirectly on us.

On April 30, 2001, we filed with the Federal Energy Regulatory Commission seeking approval of a transaction in which our stock would be transferred to a newly-created indirect wholly-owned subsidiary of Edison International. The filing, which was approved by the Federal Energy Regulatory Commission on May 14, 2001, was made in connection with a financing under consideration by Edison International, in which some or all of our stock would be pledged by the newly-created company to its lenders in connection with the contemplated financing. Under the financing, the newly-created company would issue debt, remit the proceeds of the financing to Edison International to refinance a portion of its indebtedness and pledge our stock as collateral for the debt. If this financing were completed, and there was a subsequent event of default under the financing, this could result in a change in control of us if the secured lenders in the financing were to foreclose on our stock. If this were to occur, it would be an event of default under our current corporate credit facilities, which might trigger cross-defaults in other agreements to which we are a party. In connection with the process of amending our senior credit facilities, we are discussing with the lenders modifications to the change in control provision. We cannot give any assurance that this proposed financing will be made on the terms presently contemplated or that our lenders will agree to modifications to the change in control provision.

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. The federal and state, legislative and regulatory initiatives 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.

Our trading and price risk management activities are conducted through our subsidiary, Edison Mission Marketing & Trading, Inc., which is currently rated investment grade ("BBB-" by Standard and Poor's). As part of obtaining an investment grade rating for this subsidiary, we have entered into a support agreement that 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.

We own a 40% interest in 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 $499 million at March 31, 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 have agreed on a Phase I Agreement for the period from January 1, 2001 through June 30, 2001. This agreement provides 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. To date, PT PLN has made fixed payments due under the Phase I Agreement totaling $52 million as scheduled. 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. Paiton Energy has received lender approval of the Phase I Agreement, and Paiton Energy has also entered into a lender interim agreement under which lenders have 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. Based on the current status of negotiations between Paiton Energy and PT PLN, it is not likely that a long-term restructuring of the tariff will be completed by June 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 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. At March 31, 2001, no accrual had been recorded in connection with this litigation. We believe that the outcome of this litigation will not have a material adverse effect on our consolidated financial position or results of operations.

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.

Project		Local Currency		U.S. Currency
				(in millions)
Italian Wind Projects(i)		36 billion Italian Lira		$16

Projects	Local Currency	U.S. Currency
		(in millions)
Italian Wind Projects(i)	6 billion Italian Lira	$3
CBK Project(ii)	—	58.5

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.

Projects	Local Currency	U.S. Currency
		(in millions)
Paiton(i)	—	$5
ISAB(ii)	86 billion Italian Lira	39

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 "—California Power Crisis" for further discussion.

Some of our subsidiaries have entered into indemnification agreements, under which the subsidiaries agreed to repay capacity payments to the projects' power purchasers in the event the projects unilaterally terminate their performance or reduce their electric power producing capability during the term of the power contracts. Obligations under these indemnification agreements as of March 31, 2001, if payment were required, would be $249 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.

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 March 31,
	2001		2000
	(Unaudited)
	(in millions)
Operating Revenues	$	376.2	$	116.5
Operating Income		79.9		36.1
Net Income		79.9		35.7

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 March 31,
	2001		2000
	(Unaudited)
	(in millions)
Operating Revenues	$	112.2	$	77.9
Operating Income		86.7		40.3
Net Income		56.8		24.2

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 March 31, 2001, we owned interests in 33 domestic and 40 international operating power projects with an aggregate generating capacity of 28,036 megawatts (MW), of which our share was 22,759 MW. At that date, one domestic and four international projects, totaling 1,331 MW of generating capacity, of which our anticipated share will be approximately 826 MW, were in construction. At March 31, 2001, we had consolidated assets of $14.1 billion and total shareholder's equity of $2.6 billion.

Our operating revenues are derived primarily from electric revenues and equity in income from power projects. Electric revenues accounted for 86% and 94% of our total operating revenues during the three-month periods ended March 31, 2001 and March 31, 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.

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 increased $61.2 million for the first quarter of 2001, compared to the first quarter of 2000. The increase resulted from higher electric revenues during the first quarter of 2001 from the Homer City plant due to higher energy prices and from the Illinois Plants due to increased generation from the coal units as compared to the same prior year period.

We have expanded our trading operations beyond the traditional marketing of our electric power as a result of the Citizens Power LLC acquisition in September 2000. Net losses from energy trading activities were $4.1 million for the first quarter of 2001. There were no comparable gains or losses for the same prior year period. Total gains and losses from price risk management activities were $23 million and ($1.7) million for the first quarter of 2001 and 2000, respectively. 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.

Equity in income from investments increased $49 million during the first quarter of 2001, compared to the same prior year period. The increase was primarily the result of higher revenues from cogeneration projects due to higher energy pricing and higher revenues from oil and gas investments due to higher oil and gas prices.

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 $57.7 million for the first quarter of 2001, compared to the first quarter of 2000. The increase in fuel expense resulted from higher fuel costs at the Illinois Plants primarily due to higher natural gas and fuel oil prices. In addition, fuel costs increased at the Homer City plant due to increased production during the first quarter of 2001, as compared to the first quarter of 2000, when the plant experienced more planned outages.

The increase in plant operations during the first quarter of 2001, as compared to the first quarter of 2000, 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 first quarter of 2000. In addition, plant operations increased due to higher major maintenance costs at the Illinois Plants during the first quarter of 2001.

Depreciation and amortization expense decreased $10.7 million for the first quarter of 2001, compared to the same prior year period. 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 first quarter of 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 $78 million during the first quarter of 2001, compared to the first quarter of 2000. 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. In addition, operating losses from the Illinois Plants were lower during the first quarter of 2001, compared to the first quarter of 2000.

Operating revenues decreased $6.1 million for the first quarter of 2001, compared to the first quarter of 2000. The decrease resulted primarily from lower electric revenues from the Loy Yang B plant in Australia due to a 15.9% decrease in the average exchange rate of the Australian dollar compared to the U.S. dollar at the three-month period ended March 31, 2001, compared to the same prior year period.

Net losses from price risk management activities were $0.5 million for the first quarter of 2001. There were no comparable gains or losses for the same prior year period. The losses 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.

Fuel and plant operations decreased $1.8 million for the first quarter of 2001, compared to the first quarter of 2000. The decrease resulted from lower fuel costs at the Loy Yang B plant due to the decrease in the average exchange rate of the Australian dollar compared to the U.S. dollar and lower costs resulting from renegotiation of a coal contract.

Depreciation and amortization expense decreased $2.4 million for the first quarter of 2001, compared to the first quarter of 2000. The decrease was primarily due to the decrease in the average exchange rate of the Australian dollar compared to the U.S. dollar.

Operating income decreased $2 million during the first quarter of 2001, compared to the first quarter of 2000. The decrease was due to lower operating income from the Loy Yang B plant resulting from a decrease in the value of the Australian dollar compared to the U.S. dollar.

Operating revenues decreased $80.2 million for the first quarter of 2001, compared to the first quarter of 2000. 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 a 9.2% decrease in the average exchange rate of the pound sterling compared to the U.S. dollar at the three-month period ended March 31, 2001, compared to the same prior year period. The time weighted average System Marginal Price dropped from £21.3/MWh during the quarter ended March 31, 2000 to £18.6/MWh during the quarter ended March 31, 2001. The First Hydro plant, Ferrybridge and Fiddler's Ferry plants and the Iberian Hy-Power plants are expected to provide higher electric revenues during the winter months.

Net losses from price risk management activities were $10.2 million for the three months ended March 31, 2001. There were no comparable gains or losses for the same prior year period. 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 decreased $1.9 million during the first quarter of 2001, compared to the same prior year period. The decrease reflects losses from commercial operation of the ISAB project which commenced in April 2000. We had no comparable results for the ISAB project in the first quarter of 2000.

Fuel and plant operations decreased $26.8 million for the first quarter of 2001, compared to the first quarter of 2000. The decrease in fuel expense resulted primarily from lower fuel costs at the First Hydro plant due to a drop in energy prices and lower pumping costs during the first quarter of 2001 and due to a decrease in the average exchange rate of the pound sterling compared to the U.S. dollar. The decrease in plant operations was primarily due to a decrease in the average exchange rates of the pound sterling compared to the U.S. dollar and lower production at the Ferrybridge and Fiddler's Ferry plants during the first three months of 2001. Partially offsetting these decreases were higher fuel costs and plant operation expenses for the Doga project due to increased production in the first quarter of 2001, as compared to the same prior year period.

Depreciation and amortization expense decreased $2.5 million for the first quarter of 2001, compared to the same prior year period. The decrease was primarily due to the decrease in the average exchange rates of the pound sterling compared to the U.S. dollar.

Operating income decreased $63 million during the first quarter of 2001, compared to the first quarter of 2000. The decrease was due to lower operating income from the Ferrybridge and Fiddler's Ferry plants and the First Hydro plant.

Net gains from price risk management activities were $0.9 million for the three months ended March 31, 2001. There were no comparable gains or losses for the same prior year period. 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. During the first quarter of 2001, an adjustment was made to reflect the decrease in market value of stock equivalent units.

Interest and other income (expense) increased $6.1 million for the first quarter of 2001, compared to the first quarter of 2000. The increase was primarily due to foreign exchange gains on intercompany loans.

Interest expense decreased $19.1 million for the first quarter of 2001 compared to the first quarter of 2000. 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 and favorable changes in foreign exchange rates.

During the first quarter of 2001, we recorded an effective tax provision rate of 31% 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 quarter of 2000 of 33%.

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.

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 March 31, 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 March 31, 2001, we had cash and cash equivalents of $450.5 million and had available a total of $22 million of borrowing capacity under a $500 million revolving credit facility that expires on October 10, 2001. We had no borrowing capacity under our $300 million senior credit facility and our $700 million senior credit facility, both scheduled to expire on May 29, 2001. We are in the process of amending these credit facilities to extend the expiration date from May 29, 2001 to October 10, 2001. On April 5, 2001, we issued $600 million of 9.875% senior notes, due on April 15, 2011. We used the proceeds to reduce borrowings under our credit facilities and pay for transaction costs.

Net cash used in operating activities totaled $138.2 million during the first quarter of 2001, compared to net cash provided by operating activities of $32.4 million for the first quarter of 2000. The decrease is primarily due to higher working capital requirements. Net working capital at March 31, 2001 was ($1,952) million compared to ($1,703.9) million at December 31, 2000. The decrease reflects the net decrease in cash and cash equivalents at March 31, 2001.

Net cash used in financing activities totaled $108.6 million for the three months ended March 31, 2001, compared to net cash provided by financing activities of $363.2 million during the three months ended March 31, 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 addition, a dividend of $32.5 million was paid to Edison International, our parent company, compared to $22 million in the first quarter of 2000. As of March 31, 2001, we had recourse debt of $2.2 billion, with an additional $5.5 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 $229.2 million for the three months ended March 31, 2001 from $100.6 million for the three months ended March 31, 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 first quarter of 2001. See "—California Power Crisis" for further discussion. In addition, $20 million was paid for the purchase of the 50% interest in the CBK project in February 2001. In March 2000, $21.7 million was paid towards the purchase price and contributions for the Italian Wind Projects. We invested $77.6 million and $65.2 million in the first quarter of 2001 and 2000, respectively, in new plant equipment principally related to the Sunrise project, the Homer City plant and Illinois Plants in 2001 and the Homer City plant and Illinois Plants in 2000.

On January 17, 2001, we amended our articles of incorporation and our bylaws to include so-called "ring-fencing" provisions 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 their respective investment grade ratings. These ring-fencing provisions are intended to preserve us as a stand-alone investment grade rated entity despite the current credit difficulties of Edison International and Southern California Edison. 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 and Southern California Edison. In January 2001, 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, we cannot assure you that Standard & Poor's and Moody's will not downgrade us below investment grade, whether as a result of the California power crisis or otherwise. Furthermore, we cannot predict what effects any investigation or subsequent actions by California governmental authorities, including the California Public Utilities Commission, may have on Edison International or us. See "Commitments and Contingencies—California Power Crisis."

A downgrade in our credit rating below investment grade 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 that are available for distribution may, subject to applicable law and the terms of financing arrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to us or to an affiliate of ours.

We have three corporate credit facilities that are scheduled to expire on May 29, 2001 (in a total amount of $850 million) and October 2001 (in an amount of $425 million). As of April 23, 2001, we have borrowed or issued letters of credit aggregating $1.225 billion under these credit facilities and have an unused capacity of approximately $50 million. We are in the process of amending these credit facilities to extend the expiration date from May 29, 2001 to October 10, 2001. We plan to refinance these credit facilities through modifications to our existing credit facilities or by entering into new facilities prior to their expiration. Our corporate cash requirements in 2001 are expected to exceed cash distributions from our subsidiaries. Our corporate cash requirements in 2001 include:

On April 5, 2001, we issued $600 million of 9.875% senior notes, due on April 15, 2011. We used the proceeds of that offering to repay indebtedness, including mandatory repayments of $225 million, which also reduced the amount available under the corporate facilities. We believe the proceeds from this offering will be adequate to meet our projected net cash requirements in 2001. In addition, to reduce debt and to provide additional liquidity, we may sell our interest in individual projects in our project portfolio. Under one of our credit facilities, we are required to use 50% of the net proceeds from the sale of assets and 75% of the net proceeds from the issuance of capital markets debt to repay senior bank indebtedness until the aggregate commitment amount under the corporate facilities is reduced to $1 billion. There is no assurance that we will be able to sell assets on favorable terms or that the sale of individual assets will not result in a loss. While we cannot assure you that we will be able to enter into modifications of our existing credit facilities or obtain new facilities under similar terms and rates, we believe our corporate financing plans will be successful in meeting our cash and credit requirements in 2001.

During 2001, the estimated capital expenditures of our subsidiaries are $253 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.

One of our subsidiaries, Edison First Power, has defaulted on its financing documents related to the acquisition of the Fiddler's Ferry and Ferrybridge power plants. The financial performance of the Fiddler's Ferry and Ferrybridge power plants has not matched our expectations, largely due to lower energy power prices resulting primarily from increased competition, warmer-than-average weather and

uncertainty surrounding the new electricity trading arrangements. See "—Market Risk Exposures—United Kingdom." As a result, Edison First Power has decided to defer some environmental capital expenditures originally planned to increase plant utilization and therefore is currently in breach of milestone requirements for the implementation of the capital expenditures program set forth in the financing documents relating to the acquisition of these plants. In addition, 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.

Edison First Power is currently in discussions with the relevant financing parties to revise the required capital expenditure program, to waive (i) the breach of the financial ratio covenant for 2000, (ii) a technical breach of requirements for the provision of information that was delayed due to uncertainty regarding capital expenditures, and (iii) other related technical defaults. Edison First Power is in the process of requesting the necessary waivers and consents to amendments from the financing parties. We cannot assure you that waivers and consents to amendments will be forthcoming. 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 debt service requirements for the first quarter of 2001.

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 March 31, 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 our guarantee remains in force notwithstanding any breaches under Edison First Power's acquisition financing documents.

As a result of the change in the prices of power in the U.K., we are considering the sale of 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. However, if a decision to sell the Ferrybridge and Fiddler's Ferry power plants were made, it is likely that the fair value of the assets would be substantially below their book value at March 31, 2001. Our net investment in our subsidiary that holds the Ferrybridge and Fiddler's Ferry power plants and related debt was $991 million at March 31, 2001.

The following table summarizes our consolidated capital commitments as of March 31, 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	396		2001-2003	Acquisition of Sunrise Project, 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	516		2001-2005	Environmental Matters and Regulations
Project Acquisition for the Italian Wind Projects	16		2001-2002	Firm Commitment for Asset Purchase
Equity Contribution for the Italian Wind Projects	3		2001-2002	Firm Commitments to Contribute Project Equity
Equity Contribution for the CBK Project	59		2003	Firm Commitments to Contribute Project Equity

or a portion of its future payments. At March 31, 2001, accounts receivable due to these partnerships from Southern California Edison were $472 million. Our share of these receivables was $234 million.

On April 20, 2001, a prehearing conference was held, at which the parties involved were asked to inform the California Public Utilities Commission of their view of the impact of the Memorandum on specified issues from a draft of a proposed order released by the Commission on March 15, 2001, how to expedite resolution of those issues, and how to conduct the remainder of the investigation to the extent other issues and other parties are not affected. This proposed order instituted an investigation into whether California's investor-owned utilities have complied with past Commission decisions authorizing the formation of their holding companies and governing affiliate transactions, as well as applicable statutes. At this prehearing conference, no definitive rulings were made on any issue in the investigation, including the Commission's resolution of the investigation, as called for in the Memorandum, nor were any views expressed on Southern California Edison's characterization of the impact on the investigation of the Memorandum. Several parties, including Edison International, raised objections to the Commission's assertion of jurisdiction over utility holding companies. The Commission is expected to issue a further ruling concerning the scope and scheduling of the investigation and also to schedule a further prehearing conference. We cannot predict what the effects of any investigation or subsequent actions by the Commission may have on Edison International or indirectly on us.

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.

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. At March 31, 2001, no accrual had been recorded in connection with this litigation. 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)
Italian Wind Projects(i)		36 billion Italian Lira		$16

Projects	Local Currency	U.S. Currency
		(in millions)
Italian Wind Projects(i)	6 billion Italian Lira	$3
CBK Project(ii)	—	58.5

Projects	Local Currency	U.S. Currency
		(in millions)
Paiton(i)	—	$5
ISAB(ii)	86 billion Italian Lira	39

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 uncontracted 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.

Our electric revenues were increased by $3.1 million and $36.6 million for the three months ended March 31, 2001 and 2000, respectively, as a result of electricity rate swap agreements and other hedging mechanisms. An electricity rate swap agreement is an exchange of a fixed price of electricity for a floating price. As a seller of power, we receive the fixed price in exchange for a floating price, like the index price associated with electricity pools.

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 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 Exelon Generation to make capacity payments for the plants under contract and energy payments 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. 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 are the direct result of an October 1997 request by the Minister for Science, Energy and Industry who asked the U.K. Director General of Electricity Supply to review the operation of the pool pricing system. In July 1998, the Director General proposed that the current structure of contracts for differences and compulsory trading via the pool at half-hourly clearing prices bid a day ahead be abolished. The U.K. Government accepted the proposals in October 1998 subject to reservations. Following this, the Government and the Director General published further proposals in July and October 1999. The proposals include, among other things, the establishment of a spot market or voluntary short-term power exchanges operating from 24 to 3¹/2 hours before a trading period; 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 will replace the current contracts for differences, but will function in a similar manner. However, it remains difficult to evaluate the future impact of the proposals. A key feature of the new electricity trading 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, allows for the implementation of new electricity trading arrangements and the necessary amendments to generators' licenses. Various key documents were designated by the Secretary of State and signed by participants on August 14, 2000; however, due to difficulties encountered during testing, implementation of the new electricity trading arrangements was delayed from November 21, 2000 until March 27, 2001.

The Utilities Act sets a principal objective for the Government and the Director General 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 recognition that license holders should be able to finance their activities. The Act also contains new powers for the Government to issue guidance to the Director General on social and environmental matters, changes to the procedures for modifying licenses and a new power for the Director General to impose financial penalties on

companies for breach of license conditions. We will be monitoring the operation of these new provisions. See "—Financing Plans."

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 $3.3 million and $5.1 million of additional interest expense for the three months ended March 31, 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 $1 billion consisting of commercial paper and bank borrowings at March 31, 2001. The fair values of these obligations approximated their carrying values at March 31, 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 $6.7 billion at March 31, 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 5%, 12% and 9%, respectively (determined by the change in the exchange rates from December 31, 2000 to March 31, 2001). The decrease in value of these currencies was the primary reason for the foreign currency translation loss of $96.6 million during the first quarter 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 March 31, 2001, the outstanding notional amount of the contracts totaled $83 million, consisting of contracts to exchange U.S. dollars to pound sterling with varying maturities ranging from April 2001 to July 2002. During the first quarter of 2001, we recognized a foreign exchange loss of approximately $63,000 related to the fuel purchases underlying the contracts that matured in January, February and March 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. We cannot assure you 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 $42 million for the remainder of 2001 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 $48 million for the remainder 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 $19 million for the remainder 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.

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.

Since the adoption of the United Nations Framework 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 not been submitted to the Senate for ratification, and the Bush administration has announced its opposition to the Kyoto Protocol. Apart from the Kyoto Protocol, we may be affected by future federal or state legislation related to controlling greenhouse gas emissions. In particular, the

Illinois legislature is considering legislation that would require the Illinois Environmental Protection Agency and Illinois Pollution Control Board to develop and promulgate regulations to limit emissions of carbon dioxide (as well as sulfur dioxide, nitrogen oxides and mercury) from fossil fuel-fired electric generating plants. If the United States ratifies the Kyoto Protocol or we otherwise become subject to limitations on emissions of carbon dioxide from our plants, these requirements could have a significant impact on our operations.

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.

On April 18, 2001, Unit 6 at the Joliet Station (314 MW) was taken off line after a coal-dust explosion occurred in the building housing the unit. We expect the repairs to be completed and the unit restored to commercial operations by May 22, 2001. Under our insurance program, we are obligated for the property damage insurance deductible of $2 million, which approximates the estimated repair costs.

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
10.1		Indenture, dated as of April 5, 2001, among Edison Mission Energy and United States Trust Company of New York as Trustee, incorporated by reference to Exhibit 4.20 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.1.1		Form of 9.875% Senior Note due 2011 (included in Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 24, 2001).
10.2		Registration Rights Agreement, dated as of April 2, 2001, among Edison Mission Energy and Credit Suisse First Boston and Westdeutsche Landesbank Girozentrale (Düsseldorf) as representatives of the Initial Purchasers, incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 24, 2001.

The registrant filed the following report on Form 8-K during the quarter ended March 31, 2001.

Date of Report		Date Filed		Item(s) Reported
March 22, 2001		March 22, 2001		7, 9

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 March 31,
			2001			2000
			(Unaudited)
Operating Revenues
	Electric revenues		$	665,219		$	691,314
	Equity in income from energy projects			64,190			29,303
	Equity in income from oil and gas investments			20,450			7,796
	Net gains (losses) from energy trading and price risk management			9,037			(1,749	)
	Operation and maintenance services			11,253			10,259

		Total operating revenues		770,149			736,923

Operating Expenses
	Fuel			281,546			276,299
	Plant operations			212,314			187,962
	Operation and maintenance services			7,441			7,981
	Depreciation and amortization			85,611			102,995
	Long-term incentive compensation			(3,714	)		—
	Administrative and general			37,498			34,123

		Total operating expenses		620,696			609,360

	Operating income			149,453			127,563

Other Income (Expense)
	Interest and other income (expense)			14,256			8,163
	Interest expense			(153,854	)		(172,971	)
	Dividends on preferred securities			(6,290	)		(8,107	)

		Total other income (expense)		(145,888	)		(172,915	)

	Income (loss) before income taxes			3,565			(45,352	)
	Provision (benefit) for income taxes			1,099			(15,191	)

Income (Loss) Before Accounting Change				2,466			(30,161	)
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)			$	8,467		$	(12,471	)

			Three Months Ended March 31,
			2001			2000
			(Unaudited)
Net Income (Loss)			$	8,467		$	(12,471	)
Other comprehensive expense, net of tax:
	Foreign currency translation adjustments, net of income tax benefit of $2,349 and $807 in 2001 and 2000, respectively			(96,645	)		(43,533	)
	Unrealized 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 losses arising during period, net of income tax benefit of $17.4 million		(38,711	)		—
		Add: reclassification adjustment for losses included in net income, net of income tax benefit of $15.6 million		28,271			—

	Net unrealized losses on derivatives qualified as cash flow hedges			(240,679	)		—

Other comprehensive expense				(337,324	)		(43,533	)

Comprehensive Loss			$	(328,857	)	$	(56,004	)

			March 31, 2001		December 31, 2000
			(Unaudited)
Assets
Current Assets
	Cash and cash equivalents		$	450,536	$	962,865
	Accounts receivable—trade, net of allowance of $1,126 in 2001 and 2000			408,014		506,936
	Accounts receivable—affiliates			159,731		156,862
	Assets under energy trading and price risk management			221,530		251,524
	Inventory			272,650		279,864
	Prepaid expenses and other			42,193		49,004

		Total current assets		1,554,654		2,207,055

Investments
	Energy projects			2,195,253		2,044,043
	Oil and gas			34,435		43,549

		Total investments		2,229,688		2,087,592

Property, Plant and Equipment				10,279,069		10,585,710
	Less accumulated depreciation and amortization			756,934		721,586

		Net property, plant and equipment		9,522,135		9,864,124

Other Assets
	Long-term receivables			267,897		267,599
	Goodwill			272,686		289,146
	Deferred financing costs			105,406		113,652
	Long-term assets under energy trading and price risk management			35,418		56,695
	Restricted cash and other			121,463		131,228

		Total other assets		802,870		858,320

Total Assets			$	14,109,347	$	15,017,091

			March 31, 2001			December 31, 2000
			(Unaudited)
Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable—affiliates		$	29,570		$	25,489
	Accounts payable and accrued liabilities			536,927			736,213
	Liabilities under energy trading and price risk management			355,046			281,657
	Interest payable			104,532			123,354
	Short-term obligations			1,007,084			883,389
	Current portion of long-term incentive compensation			7,600			93,000
	Current maturities of long-term obligations			1,465,909			1,767,898

		Total current liabilities		3,506,668			3,911,000

Long-Term Obligations Net of Current Maturities				5,248,774			5,334,789

Long-Term Deferred Liabilities
	Deferred taxes and tax credits			1,429,371			1,611,485
	Deferred revenue			407,933			460,481
	Long-term incentive compensation			45,084			51,766
	Long-term liabilities under energy trading and price risk management			276,865			58,016
	Other			296,785			314,610

		Total long-term deferred liabilities		2,456,038			2,496,358

Total Liabilities				11,211,480			11,742,147

Preferred Securities of Subsidiaries
	Company-obligated mandatorily redeemable security of partnership holding solely parent debentures			150,000			150,000
	Subject to mandatory redemption			161,040			176,760

		Total preferred securities of subsidiaries		311,040			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			377,363			401,396
	Accumulated other comprehensive loss			(484,072	)		(146,748	)

Total Shareholder's Equity				2,586,827			2,948,184

Total Liabilities and Shareholder's Equity			$	14,109,347		$	15,017,091

			Three Months Ended March 31,
			2001			2000
			(Unaudited)
Cash Flows From Operating Activities
	Net income (loss)		$	8,467		$	(12,471	)
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
		Equity in income from energy projects		(64,190	)		(29,303	)
		Equity in income from oil and gas investments		(20,450	)		(7,796	)
		Distributions from energy projects		5,175			31,600
		Dividends from oil and gas investments		29,296			—
		Depreciation and amortization		85,611			102,995
		Deferred taxes and tax credits		(10,438	)		(44,543	)
		Amortization of discount on short-term obligations		1,106			—
		Cumulative effect on prior years of change in accounting, net of tax		(6,001	)		(17,690	)
	(Increase) decrease in accounts receivable			96,053			(1,476	)
	(Increase) decrease in inventory			4,933			(64,578	)
	Decrease in prepaid expenses and other			9,295			7,322
	Increase (decrease) in accounts payable and accrued liabilities			(282,894	)		102,841
	Increase (decrease) in interest payable			(18,971	)		7,482
	Decrease in long-term incentive compensation			(6,682	)		(46,523	)
	Decrease in net assets under risk management			34,395			—
	Other, net			(2,939	)		4,491

		Net cash provided by (used in) operating activities		(138,234	)		32,351

Cash Flows From Financing Activities
	Borrowings long-term obligations			930,020			2,101,024
	Payments on long-term obligations			(1,130,180	)		(1,767,702	)
	Short-term financing, net			124,060			51,886
	Cash dividends to parent			(32,500	)		(22,000	)

		Net cash provided by (used in) financing activities		(108,600	)		363,208

Cash Flows From Investing Activities
	Investments in and loans to energy projects			(148,222	)		(52,089	)
	Purchase of common stock of acquired companies			(20,000	)		(8,360	)
	Capital expenditures			(77,647	)		(65,151	)
	Decrease in restricted cash			7,669			32,960
	Other, net			8,980			(7,989	)

		Net cash used in investing activities		(229,220	)		(100,629	)

Effect of exchange rate changes on cash				(36,275	)		(9,469	)

Net increase (decrease) in cash and cash equivalents				(512,329	)		285,461
Cash and cash equivalents at beginning of period				962,865			398,695

Cash and cash equivalents at end of period			$	450,536		$	684,156

Date:	May 14, 2001	/s/ KEVIN M. SMITH

		KEVIN M. SMITH Senior Vice President and Chief Financial Officer

Three Months Ended	Americas			Asia Pacific		Europe, Central Asia, Middle East and Africa		Corporate/ Other			Total
	(Unaudited)
	(in millions)
March 31, 2001
Operating revenues	$	408.7		$	48.8	$	311.7	$	0.9		$	770.1
Operating income (loss)		76.3			25.6		77.4		(29.9	)		149.4
Total assets	$	6,605.7		$	2,159.3	$	4,859.0	$	485.3		$	14,109.3
March 31, 2000
Operating revenues	$	277.9		$	55.0	$	404.0	$	—		$	736.9
Operating income (loss)		(1.7	)		27.6		140.4		(38.7	)		127.6
Total assets	$	7,650.7		$	2,790.7	$	5,107.1	$	84.6		$	15,633.1