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

Form 10-Q

(Mark one)

For the Quarterly Period Ended September 30, 2002

or

For the transition period from                              to                             

Commission file number 000-24890

EDISON MISSION ENERGY
(Exact name of registrant as specified in its charter)

Registrant's telephone number, including area code: (949) 752-5588

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES ý NO o

        Number of shares outstanding of the registrant's Common Stock as of November 11, 2002: 100 shares (all shares held by an affiliate of the registrant).

TABLE OF CONTENTS

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In thousands)

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

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EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

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

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EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands)

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

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EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands)

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

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EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

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

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EDISON MISSION ENERGY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2002

NOTE 1. GENERAL

        In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to present fairly the consolidated financial position and results of operations for the periods covered by this report. The results of operations for the nine months ended September 30, 2002 are not necessarily indicative of the operating results for the full year.

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

        Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on net income or shareholder's equity.

Current Developments

        A number of significant developments have adversely affected independent power producers and subsidiaries of major integrated energy companies who sell a sizable portion of their generation into the wholesale energy market (sometimes referred to as merchant generators). These developments include depressed market prices in wholesale energy markets both in the United States and United Kingdom, significant declines in the credit ratings of most major market participants, and the decline of liquidity in the energy markets as a result of tightening credit and increasing concern about the ability of counter-parties to perform their obligations. In addition, many merchant generators and power trading firms have announced plans to improve their financial position through asset sales, the cancellation or deferral of substantial new development, significant reductions in or elimination of trading activities, decreases in capital expenditures, including cancellations of orders for new turbines, and reductions in operating costs.

Our Situation

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

        Notwithstanding these efforts, in 2002, we have been affected by lower wholesale prices of energy and capacity, particularly at our Homer City facilities in Pennsylvania, and by the diminished ability to enter into forward contracts for the sale of power primarily from these facilities because of the credit constraints affecting us and many of our counter-parties.

        Our Illinois Plants have been largely unaffected by these developments because Exelon Generation is under contract to buy substantially all of the capacity of these units for the balance of 2002. However, as permitted by the power purchase agreements, Exelon Generation has advised us that it will not purchase 2,684 megawatts (MW) of the capacity from our coal-fired units and 1,864 MW of capacity from our Collins Station and small peaking units for 2003 and 2004 and Exelon Generation

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has the further right to release an additional 3,043 MW for 2004. As a result, beginning in 2003, the portion of our generation to be sold into the wholesale markets will significantly increase, thereby increasing our merchant risk. See "Management's Discussion and Analysis of Results of Operations and Financial Condition—Market Risk Exposures—Illinois Plants."

        As a result of these and other factors, Moody's downgraded our credit rating and the credit ratings of our largest subsidiary, Edison Mission Midwest Holdings, on October 1, 2002 as shown in the following table:

        In addition, Standard & Poor's has placed our credit ratings on CreditWatch with negative implications. See "Management's Discussion and Analysis of Results of Operations and Financial Condition—Liquidity and Capital Resources—Credit Ratings."

        Against this background, we have undertaken a number of actions to reduce our commitments and expenditures, thereby improving our cash flow. These actions include:

•

a reduction in our capital expenditure program by $363 million for the next five years as the result of the cancellation of an outstanding order for nine turbines and suspension of work on two selective catalytic reduction systems (commonly referred to as SCRs) for our Powerton Station;



•

suspension, beginning in January 2003, of operations at Units 1 and 2 of our Will County plant and Units 4 and 5 of our Collins Station in Illinois in order to reduce operating costs;



•

suspension of new business development activities; and



•

implementation of plans to reduce annual general and administrative expenses by $25 million.

        We have also reduced our already modest non asset-backed trading activities in Boston, and focused almost exclusively on the sale of power from our facilities and related risk management activities.

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

NOTE 2. INVENTORY

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

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NOTE 3. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

        Unrealized gains (losses) on cash flow hedges included those related to the hedge agreement we have with the State Electricity Commission of Victoria for electricity prices from our Loy Yang B project in Australia. This contract does not qualify under the normal sales and purchases exception because financial settlement of the contract occurs without physical delivery. Approximately 46% of our accumulated other comprehensive loss at September 30, 2002 related to net unrealized losses on the cash flow hedge resulting from this contract. These losses arise because current forecasts of future electricity prices in these markets are greater than our contract prices. In addition to this contract, unrealized gains (losses) on cash flow hedges included those related to our share of interest rate swaps of our unconsolidated affiliates and the Loy Yang B project.

        As our hedged positions are realized, approximately $9.1 million, after tax, of the net unrealized gains on cash flow hedges at September 30, 2002 are expected to be reclassified into earnings during the next 12 months. Management expects that when the hedged items are recognized in earnings, the net unrealized gains associated with them will be offset. The maximum period over which we have designated a cash flow hedge, excluding those forecasted transactions related to the payment of variable interest on existing financial instruments, is 14 years.

NOTE 4. DISCONTINUED OPERATIONS

        On December 21, 2001, Edison First Power Limited completed the sale of the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom to two wholly-owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated with the plants. The sale was the result of a competitive bidding process. We acquired the plants in 1999 from PowerGen UK plc for £1.3 billion. Net proceeds from the sales of £643 million were used to repay borrowings outstanding under the existing debt facility related to the acquisition of the power plants. We recorded an after-tax loss during 2001 of $1.1 billion related to the loss on disposal of these assets. The results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in the consolidated financial statements in accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The consolidated financial statements have been restated to conform to discontinued operations treatment for all historical periods presented.

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

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

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Accordingly, the majority of these contracts were recorded at fair value with subsequent changes in fair value recorded through the income statement.

        Summarized results of discontinued operations are as follows:

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

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NOTE 5. RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS

Non-Trading Derivative Financial Instruments

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

        In assessing the fair value of our non-trading derivative financial instruments, we use a variety of methods and assumptions based on the market conditions and associated risks existing at each balance sheet date. The fair value of commodity price contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. The following table summarizes the maturities, the valuation method and the related fair value of our commodity risk management assets and liabilities (as of September 30, 2002) (in millions):

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

Energy Trading Derivative Financial Instruments

        On September 1, 2000, we acquired the trading operations of Citizens Power LLC and, subsequently, combined them with our risk management and trading operations, now conducted by our subsidiary, Edison Mission Marketing & Trading, Inc. As a result of a number of industry and credit related factors, we have minimized our price risk management activities and our trading activities with third parties not related to our power plants or investments in energy projects. See "Management's Discussion and Analysis of Results of Operations and Financial Condition—Current Developments." To the extent we engage in trading activities, we seek to manage price risk and create stability of future income by selling electricity in the forward markets and, to a lesser degree, to generate profit from price volatility of electricity and fuels by buying and selling these commodities in wholesale markets. Approximately 2,746 GWh of our energy trading contracts (excluding the power sales agreement with

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an unaffiliated electric utility) were physically settled during the third quarter ended September 30, 2002. We generally balance forward sales and purchase contracts and manage our exposure through a value at risk analysis as described further below.

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

        Quoted market prices are used to determine the fair value of the financial instruments related to energy trading activities, except for the power sales agreement with an unaffiliated electric utility that we purchased and restructured and a long-term power supply agreement with another unaffiliated party. We recorded these agreements at fair value based upon a discounting of future electricity prices derived from a proprietary model using a discount rate equal to the cost of borrowing the non-recourse debt incurred to finance the purchase of the power supply agreement. The following table summarizes the maturities, the valuation method and the related fair value of our energy trading assets and liabilities (as of September 30, 2002) (in millions):

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

        The unrealized gain (loss) from energy trading activities included in the above amounts was $2 million and $6.3 million for the three month periods ended September 30, 2002 and 2001, and $13.3 million and $(10.6) million for the nine month periods ended September 30, 2002 and 2001, respectively.

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NOTE 6. COMMITMENTS AND CONTINGENCIES

Capital Expenditures

        The capital program at the Illinois Plants has been reduced by $310 million for the period 2003-2005 as a result of the suspension of work related to two SCRs for the Powerton Station. As a result of the decision to suspend work on this project, we recorded an impairment charge of $25.4 million during the third quarter ended September 30, 2002, due to the write-off of capitalized costs associated with these environmental improvements. This decision to reduce capital expenditures was made in light of current market conditions. See "Management's Discussion and Analysis of Results of Operations and Financial Condition—Market Risk Exposures" and "Management's Discussion and Analysis of Results of Operations and Financial Condition—Environmental Matters and Regulations."

        On August 9, 2002, our subsidiary, Midwest Generation, LLC, exercised its option to purchase the Illinois peaker power units that were subject to a lease with a third-party lessor. As disclosed in "Off-Balance Sheet Transactions" in our 2001 Annual Report on Form 10-K, this operating lease was structured to maintain a minimum amount of equity (3% of the acquisition price) for the duration of the lease term in accordance with existing guidance for leases involving special purpose entities (sometimes referred to as synthetic leases). In order to fund the purchase, we received $255 million as repayment of the note receivable held by us and paid $300 million plus outstanding lease obligations to the owner-lessor. Accordingly, our net cash outlay was $45.7 million. See our 2001 Annual Report on Form 10-K for further information on off-balance sheet transactions.

        In September 2002, we notified Siemens Westinghouse of our election to terminate all of our equipment purchase contracts for nine turbines effective October 25, 2002. The termination of the equipment purchase order reduced our projected capital expenditures by $53 million. We recorded a $60.5 million pre-tax loss in the third quarter of 2002 related to the write-off of capitalized costs associated with the turbines.

Commercial Commitments

        The following table summarizes our consolidated commercial commitments as of September 30, 2002. Details regarding these commercial commitments are discussed in the sections following the table.

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Credit Support for Price Risk Management and Trading Activities

        Our domestic price risk management and trading activities are conducted through our subsidiary, Edison Mission Marketing & Trading, Inc. Traditionally, we have provided guarantees to support Edison Mission Marketing & Trading's contracts. On October 1, 2002, Moody's downgraded our credit rating below investment grade. Standard & Poor's has also placed our credit rating on CreditWatch with negative implications. Following the Moody's downgrade, we have provided $5.2 million (as of November 7, 2002) in letters of credit in response to requests for credit support and could be required to provide additional letters of credit or collateral in the future. It is likely that many of Edison Mission Marketing & Trading's future transactions will be supported by letters of credit or cash collateral instead of our guarantees. See "Management's Discussion and Analysis of Results of Operations and Financial Condition—Liquidity and Capital Resources—Credit Ratings."

        Our United Kingdom price risk management activities for our First Hydro project are managed through our subsidiary, Edison Mission Marketing and Services Limited. We currently provide guarantees for most of First Hydro's grid trade master agreements (referred to as GTMAs) with third-party counter-parties in order to support the credit of First Hydro. As a result of Moody's rating actions as described above, we have been and may be in the future requested to provide credit support in the form of letters of credit or cash instead of our guarantees. To this end, our subsidiary, Edison Mission Operation and Maintenance Limited, has obtained a cash collateralized credit facility in the amount of £17 million, under which letters of credit totaling £11.4 million have been issued as of October 17, 2002.

        We anticipate that sales of power from our Illinois Plants, Homer City facilities and First Hydro plants in the United Kingdom may require additional credit support over the next twelve months, depending upon market conditions and the strategies adopted for the sale of this power. Changes in forward market prices and margining requirements could further increase the need for credit support for our risk management and trading activities. We currently project the potential working capital to support our price risk management and trading activity to be between $100 million and $200 million from time to time over the next twelve months.

Firm Commitments for Asset Purchase

(i)

The Italian Wind projects are a series of power projects that are in operation or under development in Italy. Our wholly-owned subsidiary owns a 50% interest. The final purchase payments are expected to be made during the first quarter of 2003, the amount of which will depend on the number of projects that are ultimately developed. The Italian Wind expansion project is a 29 MW wind project under development in Sardinia, Italy, adjacent to an existing Italian Wind project site.

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Firm Commitments to Contribute Project Equity

(i)

CBK is a 728 MW hydroelectric power project under construction in the Philippines. At September 30, 2002, 336 megawatts have been commissioned and are operational. Our wholly-owned subsidiary owns a 50% interest. Equity was initially expected to be contributed through December 2003 commencing after full drawdown of the project's debt facility, which had been scheduled for late 2002. In October 2002, we prepaid $6.6 million of the equity contribution as a result of a failure by the contractor responsible for engineering, procurement and construction of the project to provide additional security for liquidated damages. We have obtained a waiver from lenders for the contractor's default, but expect that equity will be fully contributed before the project is able to draw upon the remaining loan commitment. In addition, as a result of Moody's credit downgrade, we posted a $41.9 million letter of credit to support the remaining portion of this obligation. For more information on Moody's rating actions, see "Management's Discussion and Analysis of Operations and Financial Condition—Liquidity and Capital Resources—Credit Ratings." In addition to these equity infusions, the project sponsors funded a special draw in December 2001 (our share of which was $10 million), as a one-time adjustment to the construction payment schedule and loan drawdown schedule agreed among the project, the sponsors and the contractor.

(ii)

The Italian Wind expansion project is a 29 MW wind project under development in Sardinia, Italy, adjacent to an existing Italian Wind project site. Our wholly-owned subsidiary owns a 50% interest. Equity is to be contributed during the first quarter of 2003. Commercial operation of the expansion is expected in the fourth quarter of 2002.

(iii)

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

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

Contingencies

Paiton Project

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

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        PT PLN and Paiton Energy signed a Binding Term Sheet on December 14, 2001 setting forth the commercial terms under which Paiton Energy is to be paid for capacity and energy charges, as well as a monthly "restructure settlement payment" covering arrears owed by PT PLN ($456 million at December 31, 2001) and the settlement of other claims. In addition, the Binding Term Sheet provides for an extension of the term of the power purchase agreement from 2029 to 2040. The Binding Term Sheet serves as the basis under which PT PLN has paid Paiton Energy beginning January 1, 2002. On June 28, 2002, Paiton Energy and PT PLN concluded negotiations on an amendment to the power purchase agreement that includes the agreed commercial terms in the Binding Term Sheet. The Binding Term Sheet will remain in effect until all conditions for effectiveness of the amendment to the power purchase agreement are completed by both parties, which conditions are required to be completed by December 31, 2002. Previously, PT PLN and Paiton Energy entered into an interim agreement (covering February to December 31, 2000), a Phase I Agreement (covering January 1 to June 30, 2001), a Phase II Agreement (covering July 1 to September 30, 2001) and a Phase III Agreement (covering October 1 to December 31, 2001). PT PLN made all of the payments to Paiton Energy as required under these agreements, which were superseded by the Binding Term Sheet. Paiton Energy continues to generate electricity to meet the power demand in the region. PT PLN has paid invoices for the months of January through August 2002, as well as the restructure settlement payments due for the months of January through September 2002, as required and in accordance with the billing procedures agreed in the Binding Term Sheet and the power purchase agreement. Paiton Energy believes that PT PLN will continue to make payments for electricity under the Binding Term Sheet while the parties work to complete the conditions precedent to the effectiveness of the amendment to the power purchase agreement.

        Our investment in the Paiton project increased to $515.8 million at September 30, 2002 from $492.1 million at December 31, 2001. The increase in the investment account resulted from our subsidiary recording its proportionate share of net income from Paiton Energy as well as its proportionate share of other comprehensive income. Our investment in the Paiton project will increase (decrease) from earnings (losses) from Paiton Energy and decrease by cash distributions. Assuming Paiton Energy remains profitable, we expect the investment account to increase substantially during the next several years as earnings are expected to exceed cash distributions.

        Under the Binding Term Sheet, past due accounts receivable due under the original power purchase agreement are to be compensated through a restructure settlement payment in the amount of US$4 million per month for a period of 30 years. If the power purchase agreement amendment does not become effective within 180 days of its signing, the parties would be entitled to revert to the terms and conditions of the original power purchase agreement in order to pursue arbitration in an international forum.

        While the Binding Term Sheet has been approved by the project lenders, Paiton Energy has not yet obtained approval of the amendment to the power purchase agreement by the project lenders. Paiton Energy and its government agency lenders have agreed to Summary Terms and Conditions for Debt Restructuring of Paiton Energy, which terms and conditions have been approved by the commercial bank lenders to the project. In addition, Paiton Energy must seek approval of the debt restructuring from its bond holders. Paiton Energy believes that the debt restructuring will receive the necessary approvals from the bond holders. Therefore, we believe that we will ultimately recover our investment in the project.

BHP Fuel Supply Agreement Arbitration

        PT Batu Hitam Perkasa (BHP), one of the other shareholders in Paiton Energy, has reinstated the pending arbitration to resolve disputes under the fuel supply agreement between BHP and Paiton Energy. The arbitration had been stayed since 1999 to allow the parties to engage in settlement discussions to restructure the coal supply chain for the Paiton project. These discussions did not result

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in a settlement of all potential claims with respect to the restructuring of the coal supply chain, and BHP recently requested that the arbitration tribunal permit BHP to amend or supplement its statement of claims to assert additional claims against Paiton Energy for breach and termination of the fuel supply agreement. BHP's total claim, to date, is $250 million.

        Paiton Energy has entered into settlement negotiations with BHP. A settlement offer has been made, and BHP has indicated that it may be willing to accept that offer, subject to the execution of acceptable documentation and the timing of payment. Such settlement is subject to Paiton Energy obtaining approval of its lenders. We believe that the outcome of this arbitration will not have a material adverse effect on our consolidated financial position or results of operations.

Lakeland Project

        The combination of the introduction of the New Electricity Trading Arrangements (replacing the "pool" system of electricity sales in the United Kingdom) and the so-called Transfer Scheme (separating the supply and distribution businesses in the United Kingdom) required material amendment to Lakeland's power sales agreement and related documents. By October 2002, agreement had been reached with Norweb Energi Ltd (the counter-party under the Lakeland power sales agreement and an indirect subsidiary of TXU Europe) and all other relevant parties as to the form of the necessary amendments, but the documentation to implement this agreement was awaiting actual signature and has not yet been signed.

        On October 14, 2002, TXU Corp., the U.S. parent company of TXU Europe, announced that it would not provide additional funding for its European business and was considering selling all or a portion of this business. On October 21, 2002, TXU Corp. announced the sale by its indirect subsidiary, TXU (United Kingdom) Ltd. of all its retail customer contracts in the United Kingdom. Concurrently, TXU announced its intention to renegotiate certain power sales agreements, including the Lakeland power sales agreement, as part of an effort to restructure its operations and preserve creditor value. TXU further indicated that failure to renegotiate these agreements or otherwise to restructure its operations could result in the equivalent of bankruptcy in the United Kingdom for one or more of TXU's subsidiaries, including possibly Norweb Energi Ltd.

        Currently, we continue to deliver power under the Lakeland power sales agreement and Norweb Energi Ltd has made all payments. We cannot determine, however, the outcome of TXU's restructuring activities in Europe, nor the effect of such activities upon the Lakeland power sales agreement. If the power sales agreement is terminated, we could operate the Lakeland project as a merchant plant, but because of current depressed power prices in the United Kingdom market, we may not be able to operate the plant profitably in the near term. Although cash is held by the project, we do not anticipate any distributions unless and until the uncertainties surrounding the power sales agreement are resolved. Further, during the fourth quarter, we will complete an asset impairment evaluation taking into

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consideration continuing developments with respect to the power sales agreement. The condensed financial position of the Lakeland project at September 30, 2002 is set forth below:

Brooklyn Navy Yard 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 has also filed an action entitled Brooklyn Navy Yard Cogeneration Partners, L.P. v. PMNC, Parsons Main of New York, Inc., Nab Construction Corporation, L.K. Comstock & Co., Inc. and The Parsons Corporation, in the Supreme Court of the State of New York, Kings County, Index No. 5966/97 asserting general monetary claims in excess of $13 million under the construction turnkey agreement. On March 26, 1998, the Superior Court in the California action granted PMNC's motion for attachment in the amount of $43 million against Brooklyn Navy Yard and attached a Brooklyn Navy Yard bank account in the amount of $0.5 million. Brooklyn Navy Yard unsuccessfully appealed the attachment order. On the same day, the court stayed all proceedings in the California action pending the New York action. PMNC's motion to dismiss the New York action was denied by the New York Supreme Court and further denied on appeal in September 1998. On March 9, 1999, Brooklyn Navy Yard filed a motion for partial summary judgment in the New York action. The motion was denied and Brooklyn Navy Yard has appealed. The appeal and the commencement of discovery were suspended until June 2000 to allow for voluntary mediation between the parties. The mediation ended unsuccessfully on March 23, 2000. On November 13, 2000, a New York appellate court issued a ruling granting summary judgment in favor of Brooklyn Navy Yard, striking PMNC's cause of action for quantum meruit, and limiting PMNC to its claims under the construction contract. On February 14, 2002, PMNC moved to amend the complaint in the New York action to add us as a defendant and to seek a $43 million attachment against us. This motion was heard on May 10, 2002, and the court issued an order denying the motion on June 21, 2002. Trial was originally scheduled for October 21, 2002, and has now been rescheduled for January 2, 2003. The parties filed motions for summary judgment in October 2002, but no hearings have been scheduled. In connection with a $407 million non-recourse project refinancing in 1997, we agreed to indemnify Brooklyn Navy Yard Cogeneration Partners and our partner from all claims and costs arising from or in connection with the contractor litigation, which indemnity has been assigned to Brooklyn Navy Yard Cogeneration Partners' lenders. Any further payments which would be due to the contractor with respect to completion of construction of the power plant would be accounted for as an addition to the power plant investment. Furthermore, our partner has executed a reimbursement agreement with us that provides recovery of up to $10 million over an initial amount, including legal fees, payable from its management fees, royalty fees, and

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distributions (if any) from the project. We believe that the outcome of this litigation will not have a material adverse effect on our consolidated financial position or results of operations.

ISAB Project

        In connection with the financing of the ISAB project, which is located near Siracusa in Sicily, Italy, we have guaranteed for the benefit of the banks financing the construction of the ISAB project our subsidiary's obligation to contribute project equity and subordinated debt totaling up to approximately $36 million. The amount of payment under the obligation is contingent upon the outcome of an arbitration proceeding brought in 1999 by the contractor of the project against ISAB Energy. On April 19, 2002, the arbitration tribunal issued a partial award on liability dismissing 10 of the contractor's 14 claims. The tribunal found there was a legal and factual basis for a "slight extension" of the guaranteed completion date and a "slight indemnification" of the contractor in relation to the four successful claims. Certain additional minor claims of the contractor, together with ISAB Energy's counterclaims for defects and delay liquidated damages, are still to be heard by the tribunal on a date to be agreed by the parties or as otherwise directed by the tribunal. We believe that the outcome of this arbitration will not have a material adverse effect on our consolidated financial position or results of operations.

Regulatory Developments Affecting Sunrise Power Company

        Sunrise Power Company, in which our wholly-owned subsidiary owns a 50% interest, sells all its output to the California Department of Water Resources under a power purchase agreement entered into on June 25, 2001. On February 25, 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints with the Federal Energy Regulatory Commission against all sellers of long-term contracts to the California Department of Water Resources, including Sunrise Power Company. The California Public Utilities Commission complaint alleged that the contracts are "unjust and unreasonable" on price and other terms, and requested that the contracts be abrogated. The California Electricity Oversight Board complaint made a similar allegation and requested that the contracts be deemed voidable at the request of the California Department of Water Resources or, in the alternative, abrogated as of a future date, to allow for the possibility of renegotiation. After hearings and intermediate rulings, on July 23, 2002, the Federal Energy Regulatory Commission dismissed with prejudice the California Public Utilities Commission and California Electricity Oversight Board complaints against Sunrise. Notwithstanding the fact that the July 23 order was, in part, a denial of rehearing sought previously, the California Public Utilities Commission and the Energy Oversight Board then filed a request for rehearing of the July 23 order. In a notice issued on September 20, 2002, the Federal Energy Regulatory Commission stated that it did not intend to act on such request. It is possible that the California Public Utilities Commission and the Energy Oversight Board may try to appeal within 60 days after the September 20, 2002 notice to the federal courts of appeal.

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

        On May 15, 2002, Sunrise was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco, by James M. Millar, "individually, and on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to the

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

Regulatory Developments Affecting Doga Project

        On August 4, 2002, the Electricity Market License Regulation was implemented in Turkey. The new regulation contains, among other things, a requirement to obtain a generation license. Historically, Doga's Implementation Contract has been its sole license. The new regulation contemplates a fixed license obtaining fee and a yearly license fee based on the amount of energy generated, which will increase the project's costs of operation by an undetermined amount. In addition, the regulation allows the insertion of provisions in the license which are different than those in the Implementation Contract.

        The effect of the new regulation is still undetermined, as the new license provisions have not been specified. The new regulation requires Doga to apply for a generation license in March or April of 2003. If actions or inactions undertaken pursuant to the new regulation directly or indirectly impede, hinder, prevent or delay the operation of the Doga facility or increase Doga's cost of performing its obligations under its project documents, this may constitute a risk event under Doga's Implementation Contract. A risk event may permit Doga to request an increase in its tariff or, under certain circumstances, request a buyout of the project.

        On October 3, 2002, Doga and several other independent power producers filed a lawsuit in the Danistay, Turkey's high administrative court, against the Energy Market Regulatory Authority for the invalidation of certain provisions of the new regulation, arguing the unconstitutionality of the imposition of new license requirements that do not take into account the vested rights of companies presently performing electricity generation pursuant to previously agreed conditions.

Federal Income Taxes

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

Indemnities

Subsidiary Indemnification Agreements

        Some of our subsidiaries have entered into indemnification agreements, under which the subsidiaries agreed to repay capacity payments to the projects' power purchasers in the event the projects unilaterally terminate their performance or reduce their electric power producing capability during the term of the power contracts. Obligations under these indemnification agreements as of September 30, 2002, if payment were required, would be $218.1 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.

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Other Indemnities

        In support of the business of our subsidiaries, we have, from time to time, entered into guarantees and indemnity agreements with respect to our subsidiaries' obligations such as debt service, fuel supply or the delivery of power, and have also entered into reimbursement agreements with respect to letters of credit issued to third parties to support our subsidiaries' obligations. We have also, from time to time, entered into guarantees and indemnification agreements with respect to acquisitions made by our subsidiaries. In this regard, we have indemnified the previous owners of the Illinois Plants, the Homer City facilities and the EcoEléctrica facilities for specified liabilities, including environmental liabilities, incurred as a result of their prior ownership of the plants. We do not believe these indemnification obligations will have a material impact on us.

Tax Indemnity Agreements

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

Litigation

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

Chicago In-City Obligation

        Pursuant to the acquisition documents for the purchase of generating assets from Commonwealth Edison, our subsidiary committed to install one or more gas-fired electric generating units having an additional gross dependable capacity of 500 MW at or adjacent to an existing power plant site in Chicago (referred to as the In-City Obligation). The acquisition documents require that commercial operation of this project commence by December 15, 2003. Due to additional capacity for new gas-fired generation in the Mid-America Interconnected Network, generally referred to as the MAIN Region, and the improved reliability of power generation in the Chicago area, we are in discussions with Commonwealth Edison and the City of Chicago regarding alternatives to construction of 500 MW of capacity, which we do not believe is needed at this time. There can be no assurance that these discussions will result in an agreement to terminate the In-City Obligation. If we were to install this additional capacity, we estimate that the cost could be as much as $320 million.

Contingent Obligations to Contribute Project Equity