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

Form 10-Q

(Mark One)

For the Quarterly Period Ended June 30, 2002

or

For the transition period from                              to                             

Commission file number 333-59348

MIDWEST GENERATION, LLC
(Exact name of registrant as specified in its charter)

Registrant's telephone number, including area code: (312) 583-6000

        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 units outstanding of the registrant's Membership Interests as of August 9, 2002: 100 units (all units held by an affiliate of the registrant).

TABLE OF CONTENTS

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

MIDWEST GENERATION, LLC

BALANCE SHEETS

(In thousands)

The accompanying notes are an integral part of these financial statements

1

MIDWEST GENERATION, LLC

BALANCE SHEETS

(In thousands)

The accompanying notes are an integral part of these financial statements

2

MIDWEST GENERATION, LLC

STATEMENTS OF OPERATIONS

(In thousands)

The accompanying notes are an integral part of these financial statements

3

MIDWEST GENERATION, LLC

STATEMENTS OF COMPREHENSIVE LOSS

(In thousands)

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

4

MIDWEST GENERATION, LLC

STATEMENTS OF CASH FLOWS

(In thousands)

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

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MIDWEST GENERATION, LLC

NOTES TO FINANCIAL STATEMENTS

(Dollars in thousands)

Note 1. General

        All adjustments, including recurring accruals, have been made that are necessary to present fairly the financial position and results of operations for the periods covered by this report. The results of operations for the six months ended June 30, 2002 are not necessarily indicative of the operating results for the full year.

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

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

Industry Developments

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

•

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



•

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



•

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



•

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



•

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

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

Our Situation

        Our plants have been largely unaffected by these developments this year, because Exelon Generation is under contract with us to buy substantially all of the capacity of our units for the balance of 2002. However, as permitted by the contracts governing our coal-fired units, Exelon Generation has advised us that they will not exercise their right to purchase 2,684 MW of the capacity of these units for 2003 and 2004. As a result, beginning in 2003, the portion of our generation to be sold into the

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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."

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

        Against this background, we have:

•

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



•

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



•

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

        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. Accumulated Other Comprehensive Income

        Accumulated other comprehensive income consisted of the following:

        Unrealized gains on cash flow hedges at June 30, 2002 include forward energy sales contracts that did not meet the normal sales and purchases exception under SFAS No. 133. These gains arise because current forecasts of future electricity prices are lower than our contract prices. As our hedged positions are realized, approximately $0.4 million, after tax, of the net unrealized gains on cash flow hedges will be reclassified into earnings during the next twelve months. The maximum period over which we have designated a cash flow hedge is two years.

Note 3. Commitments and Contingencies

Commercial Commitments

        The following table summarizes our commercial commitments as of June 30, 2002.

Capital Expenditures

        The Company's capital expenditures for the remainder of 2002 are estimated to be $50.3 million. The Company has anticipated that upgrades to its environmental controls to reduce nitrogen oxide emissions will result in expenditures of approximately $317.5 million for the periods 2003 - 2005. As a

7

result of changes in the merchant energy marketplace, the Company is evaluating its capital expenditure program, including environmental improvements. At June 30, 2002, the Company has capitalized $33.5 million as construction in progress related to environmental improvements. The Company is currently updating its capital expenditure program and evaluating whether to proceed, delay or cancel individual projects. The Company expects to complete the update of its capital expenditure program by the end of 2002.

        On August 9, 2002, the Company 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 the Company's 2001 Annual Report on Form 10-K, this operating lease was structured to maintain a minimum amount of equity (3% of the acquisition price) for the duration of the lease term in accordance with existing guidance for leases involving special purpose entities (sometimes referred to as synthetic leases). This transaction represents the only synthetic lease that the Company had outstanding at June 30, 2002. In order to effect the exercise of the Company's purchase option, it obtained repayment of its $300 million loan plus interest from Edison Mission Energy and paid $300 million plus outstanding amounts due under the lease to the owner-lessor. The purchase of these peaker units will be recorded as an asset and depreciated over their estimated useful life.

Power Purchase Agreements

        Electric power generated at the Company's power generation plants is sold under three power purchase agreements with Exelon Generation, under which Exelon Generation purchases capacity and has the right to purchase energy generated by the power generation plants. The Company initially entered into agreements with Commonwealth Edison, which we refer to as ComEd, on December 15, 1999, which were assigned to Exelon Generation in January 2001. The power purchase agreements have a term of up to five years and provide for capacity and energy payments. Exelon Generation is obligated to make capacity payments for the power generation plants under contract and energy payments for the electricity produced by these plants and taken by Exelon Generation. The capacity payments provide the power generation plants revenue for fixed charges, and the energy payments compensate the power generation plants for variable costs of production.

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

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

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

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

        If Exelon Generation does not fully dispatch the power generation plants under contract, the power generation 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.

Additional Gas-Fired Generation

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

Environmental Matters

        The Company is subject to environmental regulation by federal, state and local authorities in the United States. The Company believes that, as of the date of this report, it is in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect its financial position or results of operations. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, and future proceedings which may be taken by environmental authorities, could affect the costs and the manner in which the Company conducts its business and could cause the Company to make substantial additional capital expenditures. There is no assurance that the Company would be able to recover these increased costs from its customers or that its financial position and results of operations would not be materially adversely affected.

Interconnection Agreements

        The Company has entered into interconnection agreements with Commonwealth Edison to provide interconnection services necessary to connect its Illinois Plants with their transmission systems. Unless terminated earlier in accordance with the terms thereof, the interconnection agreements will terminate on a date mutually agreed to by both parties. This date may not exceed the retirement date of the Illinois Plants. The Company is required to compensate Commonwealth Edison for all reasonable costs associated with any modifications, additions or replacements made to the interconnection facilities or transmission systems in connection with any modification, addition or upgrade to its Illinois Plants.

Guaranty of Debt of Edison Mission Midwest Holdings and Pledge of Ownership Interests

        The Company has guaranteed Edison Mission Midwest Holdings' (its parent) third-party debt in the amount of $1.7 billion at June 30, 2002. The Company's parent also pledged the membership interests in the Company to the lenders in connection with the third-party debt arrangements.

9

Collective Bargaining Agreement

        Approximately 72% of the Company's workforce was covered by a collective bargaining agreement at June 30, 2002. The collective bargaining agreement is due to expire on December 31, 2005. The Company also has a retirement health care and other benefits plan related to its represented employees that expired on June 15, 2002. While negotiations are ongoing, the Company will continue to provide the same level of benefits until changes are made through the negotiation process.

        As described in the Company's 2001 Annual Report on Form 10-K, it has accounted for postretirement benefits obligations on the basis of a substantive plan under Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." A substantive plan means that the Company is assuming for accounting purposes that it will provide for postretirement benefits to union-represented employees following conclusion of negotiations to replace the current benefits agreement, even though it has no legal obligation to do so. If no postretirement benefits are provided, the Company would treat this as a plan termination under SFAS No. 106 and record a gain. The negotiations regarding these benefits plans are in progress and the Company expects to finalize an agreement prior to the end of 2002, although it cannot provide any assurance that these negotiations will be completed on this schedule.

Note 4. Supplemental Statements of Cash Flows Information

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

        The following discussion contains forward-looking statements that reflect our current expectations and projections about future events based on our knowledge of present facts and circumstances and our assumptions about future events. In this discussion, the words "expects," "believes," "anticipates," "estimates," "intends," "plans" and variations of these words and similar expressions are intended to identify forward-looking statements. These statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Important factors that could cause differences are set forth under "—Credit Ratings" and "—Market Risk Exposures" below, and under "—Risk Factors" in the Management's Discussion and Analysis of Results of Operations and Financial Condition included in Item 7 of Midwest Generation, LLC's Annual Report on Form 10-K for the year ended December 31, 2001. The information contained in this discussion is subject to change without notice. Unless otherwise indicated, the information presented in this section is with respect to Midwest Generation, LLC.

        The Management's Discussion and Analysis of Results of Operations and Financial Condition of this Form 10-Q discusses material changes in the results of operations, financial condition and other developments of Midwest Generation, LLC since December 31, 2001, and as compared to the second quarter and six months ended June 30, 2001. This discussion presumes that the reader has read or has access to the Management's Discussion and Analysis of Results of Operations and Financial Condition included in Item 7 of Midwest Generation, LLC's Annual Report on Form 10-K for the year ended December 31, 2001.

General

        We are a special-purpose Delaware limited liability company formed on July 12, 1999 for the purpose of owning or leasing, making improvements to and operating the power generation assets we purchased from Commonwealth Edison. We are a wholly-owned subsidiary of Edison Mission Midwest Holdings Co., an indirect wholly-owned subsidiary of Edison Mission Energy and an indirect wholly-owned subsidiary of Edison International.

        In connection with the acquisition of the power generation assets, we entered into three five-year power purchase agreements for the coal-fired stations, the Collins Station, and the peaker stations, with Commonwealth Edison. Subsequently, Commonwealth Edison, which we refer to as ComEd, assigned its rights and obligations under these power purchase agreements to Exelon Generation. We currently derive virtually all of our energy and capacity revenues from Exelon Generation under these power purchase agreements. For more information on these power purchase agreements, including Exelon Generation's notice of amount of capacity and energy purchases for 2003, see "—Market Risk Exposures."

        We have entered into a contract with a marketing affiliate for scheduling and related services and to market energy that has not been committed to be sold under the power purchase agreements with Exelon Generation and to engage in hedging activities. The marketing affiliate also purchases fuel, other than coal, and enters into fuel hedging arrangements on our behalf.

        Under the terms of the power purchase agreements with Exelon Generation, we receive significantly higher capacity payments during June through September, the summer months. Accordingly, our operating results are substantially higher during these months and lower, including expected losses, during non-summer months.

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Industry Developments

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

•

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



•

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



•

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



•

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



•

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

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

Our Situation

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

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

        Against this background, we have:

•

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



•

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



•

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

        For a discussion of our current financial condition, see "—Liquidity and Capital Resources."

12

Results of Operations

Operating Revenues

        Operating revenues increased $26.9 million and $15.4 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. The second quarter increase is primarily due to higher capacity revenue from our Collins and coal stations, higher energy revenue from scheduled price increases, and lower losses from price risk management. The increase during the six months ended June 30, 2002 is primarily due to higher capacity revenue from our Collins and coal stations and lower losses from price risk management, partially offset by lower generation overall. For both of the first six months of 2002 and 2001, 98% of our total capacity and energy revenues were derived under our three power purchase agreements with Exelon Generation.

        Our coal stations generated 6,169 GWh and 12,403 GWh of electricity during the second quarter and six months ended June 30, 2002, respectively, compared to generating 6,193 GWh and 13,143 GWh of electricity in the corresponding periods of 2001. The availability factors for the first six months of 2002 and 2001 were 79.5% and 75.4%, respectively. The availability factor is determined by the number of megawatt hours we are available to generate electricity divided by the number of megawatt hours in the period. We are not available during periods of planned and unplanned maintenance. We generally refer to unplanned maintenance as a forced outage. We had forced outage rates of 6.4% and 11.9% during the six months ended June 30, 2002 and 2001, respectively. The weighted average price for energy was $18.57/MWh during the first six months of 2002, compared to $18.02/MWh in the corresponding period of 2001. The increase in the weighted average price for energy is due to scheduled price increases in our power purchase agreement.

        Loss from price risk management activities decreased $13.7 million and $5.9 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. Income or loss from price risk management activities results from the change in market value of our futures contracts with respect to a portion of our anticipated fuel purchases that did not qualify for hedge accounting under SFAS No. 133.

Operating Expenses

        Operating expenses decreased $19.6 million and $33.5 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. Operating expenses consist of expenses for fuel, plant operations, depreciation and amortization and administrative and general expenses. The change in the components of operating expenses is discussed below.

        Fuel expenses decreased $9.3 million and $27.1 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. The decreases were primarily due to the consumption of natural gas in 2002 versus fuel oil in 2001 at the Collins Station, since natural gas costs were lower during the first six months of 2002 compared to the cost of fuel during the first six months of 2001.

        Plant operations expenses decreased $12.2 million and $10.6 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. The decreases were primarily due to lower maintenance costs from fewer forced outages and lower rent expense on our Illinois peaker power units lease due to a decline in variable lease costs tied to changes in interest rates.

        Depreciation and amortization expense increased $0.9 million and $2.1 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001 due to property, plant and equipment additions. Depreciation expense primarily relates to the acquisition of the power generation assets we purchased from Commonwealth Edison which are being depreciated over periods ranging from 20 to 40 years. The amortization expense relates to the

13

Powerton-Joliet facilities sale-leaseback and the Collins Station sale-leaseback which are being amortized over the term of the leases.

        Administrative and general expenses increased $0.9 million and $2.1 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. The increases were primarily due to higher labor and support costs charged from our parent as a contribution of services.

Other Income (Expense)

        Interest and other income decreased $2.7 million and $5.7 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. The decreases consisted primarily of decreases in interest income from lower rates on our variable rate loans to Edison Mission Energy.

        Interest expense decreased $15.9 million and $34.3 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. Interest expense primarily relates to borrowings from Edison Mission Overseas Co., a wholly-owned subsidiary of our parent, under subordinated loan agreements, and interest expense related to the lease financings of the Collins, Powerton and Joliet Stations. The decreases were primarily due to lower rates on the subordinated loans that are tied to variable interest rates and on the variable component of the Collins lease financing.

Benefit For Income Taxes

        We had effective income tax benefit rates of 35% and 38.4% in the first six months of 2002 and 2001, respectively. The effective tax rate in 2001 was different from the federal statutory rate of 35% due to state income taxes. The income tax benefit results from tax-allocation agreements with our indirect parent, Edison International.

Net Loss

        Net loss decreased $32.7 million and $43.6 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. Although we expect to generate cash flow from operations, we expect to incur losses after depreciation, amortization and interest expense for several years. Our future results of operations will depend primarily on revenues from the sale of energy, capacity and other related products, and the level of our operating expenses.

Liquidity and Capital Resources

        At June 30, 2002, we had cash and cash equivalents of $25.4 million compared to $52.6 million at December 31, 2001. Net working capital was $223.7 million at June 30, 2002 compared to $233.5 million at December 31, 2001.

        Net cash used in operating activities decreased $88.3 million in the first six months of 2002, compared to the corresponding period of 2001. The decrease in cash used in operating activities is primarily due to the timing of cash receipts and disbursements related to working capital items.

        Net cash provided by financing activities decreased $149.8 million in the first six months of 2002, compared to the corresponding period of 2001. The decrease in cash provided by financing activities is primarily due to a reduction in borrowings from our affiliate.

        Net cash used in investing activities increased $8.7 million in the first six months of 2002, compared to the corresponding period of 2001. The increase was primarily due to additional capital expenditures. Our capital expenditures for the remainder of 2002 are estimated to be $50.3 million. We

14

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

        On August 9, 2002, we exercised our option to purchase the Illinois peaker power units that were subject to a lease with a third-party lessor. As disclosed in "Off-Balance Sheet Transactions" in our 2001 Annual Report on Form 10-K, this operating lease was structured to maintain a minimum amount of equity (3% of the acquisition price) for the duration of the lease term in accordance with existing guidance for leases involving special purpose entities (sometimes referred to as synthetic leases). This transaction represents the only synthetic lease that we had outstanding at June 30, 2002. In order to effect the exercise of our purchase option, we obtained repayment of our $300 million loan plus interest from Edison Mission Energy and paid $300 million plus outstanding amounts due under the lease to the owner-lessor. The purchase of these peaker units will be recorded as an asset and depreciated over their estimated useful life.

        Our principal source of liquidity is cash on hand and future cash flow from operations. In addition, we have access to a $150 million working capital facility through our parent, which has $130 million available at June 30, 2002. We believe that we will have adequate liquidity to meet our obligations as they become due in the next twelve months. However, conditions may change, including items that are beyond our control, which could result in a shortfall of cash available to meet our debt obligations.

Debt Service Coverage Ratio

        Our parent company, Edison Mission Midwest Holdings, is the borrower under a $1.869 billion credit facility with a group of commercial banks which we have guaranteed. The funds borrowed under this facility were used to fund our original acquisition and provide working capital to our operations. As part of the original acquisition, we entered into a sale-leaseback transaction for the Collins Station and then subsequently entered into sale-leaseback transactions for the Powerton and Joliet Stations in August 2000. In order to make a distribution from Edison Mission Midwest Holdings to Edison Mission Energy, we and Edison Mission Midwest Holdings must be in compliance with the covenants specified in these agreements, including the following financial performance requirements measured on the date of distribution:

1.

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



2.

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



3.

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



4.

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

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

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

        At June 30, 2002, Edison Mission Midwest Holdings met the historical financial performance measures. However, as a result of lower wholesale energy prices and the possible downgrade of its credit rating, we cannot predict at this time whether Edison Mission Midwest Holdings will meet the forward looking tests or ratings requirements in the future.

Credit Ratings

Possible Downgrade of Us and Our Parent, Edison Mission Midwest Holdings

        We have guaranteed the obligations of our parent, Edison Mission Midwest Holdings, under a $1.869 billion credit facility. Edison Mission Midwest Holdings is currently rated Baa2 by Moody's and "BBB-" by Standard & Poor's and our lessor bonds are rated Baa2 by Moody's. On July 3, 2002, Moody's placed under review for possible downgrade our rating (lessor bonds at Baa2), and the ratings of Edison Mission Midwest Holdings Co. (bank facility at Baa2). On July 25, 2002, Standard & Poor's changed its outlook to negative from stable on its "BBB-" corporate credit ratings on Edison Mission Midwest Holdings. In addition, Standard & Poor's changed its outlook to negative from stable on the lessor bonds of the Powerton and Joliet leases. In the event of a downgrade of Edison Mission Midwest Holdings below investment grade, provisions in the agreements binding on Edison Mission Midwest Holdings and us, would limit the ability of Edison Mission Midwest Holdings to use excess cash flow to make distributions to Edison Mission Energy. There are no limitations on our ability to pay intercompany loans or distributions to Edison Mission Midwest Holdings or Edison Mission Overseas. The following table summarizes the changes in the cost of borrowing by Edison Mission Midwest Holdings and provisions restricting cash distributions (sometimes referred to as cash traps) under the applicable financing agreements:

        An increase in the cost of the borrowings of Edison Mission Midwest Holdings would result in an increase in our cost of borrowing under our long-term debt with Edison Mission Overseas, as the terms

16

and conditions of our loan agreement with Edison Mission Overseas mirrors the terms of of Edison Mission Midwest Holdings' credit agreement.

Possible Downgrade of Edison Mission Energy

        In January 2001, Standard & Poor's and Moody's downgraded Edison Mission Energy's senior unsecured credit ratings to "Baa3" from "Baa1," and "BBB-" from "A-," respectively. On July 3, 2002, Moody's placed under review for possible downgrade Edison Mission Energy's rating (senior unsecured at Baa3). On July 25, 2002, Standard & Poor's changed its outlook to negative from stable on its "BBB-" corporate credit ratings on Edison Mission Energy. There is no assurance that Standard & Poor's and Moody's will not downgrade Edison Mission Energy's credit rating below investment grade.

        As part of the sale-leaseback of the Powerton and Joliet Stations, we loaned the proceeds ($1.367 billion) to Edison Mission Energy in exchange for promissory notes in the same aggregate amount. Debt service payments by Edison Mission Energy on the promissory notes are used by us to meet our payment obligations under these leases. Furthermore, Edison Mission Energy has guaranteed our lease obligations under these leases. Edison Mission Energy's obligations under the promissory notes payable to us are general obligations of Edison Mission Energy and are not contingent upon receiving distributions from our parent Edison Mission Midwest Holdings. Accordingly, in the event of a downgrade, Edison Mission Energy would still be obligated to continue to make payments under the intercompany loans from us, notwithstanding a circumstance, if it were to occur, where Edison Mission Energy was not receiving distributions from Edison Mission Midwest Holdings. If Edison Mission Midwest Holdings were to be restricted from distributions, Edison Mission Energy would need to generate sufficient cash flow from other subsidiaries or sources in excess of their interest and overhead costs to continue to make payments under the intercompany loans from us. There is no assurance that Edison Mission Energy will have sufficient cash flow to meet these obligations. If we do not receive payment on the intercompany loans from Edison Mission Energy, we may be unable to meet our lease obligations under the Powerton and Joliet leases. This would result in an event of default under the Powerton and Joliet leases and in a cross-default under the Collins Lease and credit agreement of Edison Mission Midwest Holdings, which we have guaranteed. These events would have a material adverse affect on us.

Possible Downgrade of Edison Mission Marketing & Trading

        We have entered into a contract with a marketing affiliate, Edison Mission Marketing & Trading, for the sale of energy and capacity not contracted to Exelon Generation and for the purchase of fuel, which enables this marketing affiliate to engage in forward sales and hedging. Under this contract, we pay the marketing affiliate fees of $0.02/MWh plus emission allowance fees. Edison Mission Marketing & Trading is currently rated "BBB-" by Standard & Poor's, which is the lowest level of investment grade rating. On July 25, 2002, Standard & Poor's changed its outlook to negative from stable on its "BBB-" corporate credit ratings on Edison Mission Marketing & Trading.

        If we and our marketing affiliate are downgraded, it may become more difficult for us to enter into forward sales and hedging without providing additional collateral.

Market Risk Exposures

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

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Commodity Price Risk

        Our merchant power plants expose us to commodity price risk, which represents the potential loss that can be caused by a change in the market value of a particular commodity. Commodity price risks are actively monitored to ensure compliance with our risk management policies through our marketing affiliate. Policies are in place which limit the amount of total net exposure we may enter into at any point in time. Procedures exist which allow for monitoring of all commitments and positions with daily reporting to senior management. We perform a "value at risk" analysis in our daily business to measure, monitor and control our overall market risk exposure. The use of value at risk allows management to aggregate overall risk, compare risk on a consistent basis and identify the drivers of the risk. Value at risk measures the worst expected loss over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a single risk measurement tool, we supplement this approach with the use of stress testing and worst-case scenario analysis, as well as stop loss limits and counterparty credit exposure limits.

        As discussed further below, beginning in 2003, we will be selling a significant portion of our energy into wholesale energy markets. We intend to hedge a portion of our electric output that is not committed to be sold under long-term contracts, in order to provide more predictable earnings and cash flow. When appropriate, we manage the spread between electric prices and fuel prices, and use forward contracts, swaps, futures, or options contracts to achieve those objectives.

        With the exception of revenue generated by the three power purchase agreements with Exelon Generation, our revenues and results of operations during the estimated useful lives of the power plants will depend upon prevailing market prices for capacity, energy, ancillary services, fuel oil, coal, natural gas and associated transportation costs and emission credits in the market area known as the MAIN Region and neighboring markets. Among the factors that influence the price of power in the MAIN Region are:

•

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



•

the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market entrants, including the development of new generation facilities;



•

transmission congestion in and to the MAIN Region;



•

the market structure rules to be established for the MAIN Region and contiguous areas;



•

the cost of emission credits or allowances;



•

the availability, reliability and operation of nuclear generating plants in the MAIN Region;



•

weather conditions prevailing in the MAIN Region and surrounding areas from time to time; and



•

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

Status of the Exelon Generation Contract

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

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

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

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

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

Coal-Fired Units

(1)

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

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(2)

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

(3)

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

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

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

        Under the Collins Station power purchase agreement, Exelon Generation has the right to purchase all of the energy produced by the Collins Station. Energy prices vary depending on the total annual number of megawatt hours of energy purchased and the market price of natural gas. When purchases exceed an annual threshold of 2.7 million MWh, Exelon Generation bears all subsequent risk of changes in the market price of natural gas used to produce the energy purchased. The Collins Station is capable of burning fuel oil in lieu of natural gas, which enables us to use fuel oil when it costs less than natural gas. We have in the past purchased and have in inventory stocks of fuel oil for this purpose. Our marketing affiliate has also entered into financial transactions that hedge the price risk of a portion of our anticipated fuel purchases in 2002, although these contracts do not qualify for hedge accounting under SFAS No. 133.

        The energy and capacity from any units which do not remain subject to one of the power purchase agreements with Exelon Generation will be sold under terms, including price and quantity, to be negotiated with customers through a combination of bilateral agreements, forward energy sales and spot market sales. Thus, we will be subject to the market risks related to the price of energy and capacity described above. We intend to manage this risk, in part, by accessing both the direct customer and over-the-counter markets described below as well as using derivative financial instruments in accordance with established policies and procedures.

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

        "Into Cinergy" and "Into ComEd" are bilateral markets for the sale or purchase of electrical energy for future delivery. The emergence of "Into Cinergy," and "Into ComEd" as commercial hubs for the trading of physical power has not only facilitated transparency of wholesale power prices in the Midwest, but also aided in the development of risk management strategies that are utilized to mitigate commodity price volatility. Energy is traded in the form of physical delivery of megawatt-hours. Delivery is either made (1) into the receiving control area's transmission system (i.e., Cinergy's or

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ComEd's transmission system) by the seller's daily election of control area interface, or (2) by procuring energy generated from a source within the receiving control area. Almost all of our plants have busbar delivery that meets the "Into ComEd" delivery criteria. Performance of transactions in these markets is secured by liquidated damages and, in the case of less creditworthy counterparties, credit support provisions such as letters of credit and cash margining arrangements.

        The following table sets forth the forward month-end market prices for energy per megawatt hour for the calendar 2003 and calendar 2004 "strips", which are defined as energy purchases for the entire calendar year, as publicly quoted for sales "Into ComEd" and "Into Cinergy" during the first six months of 2002. As indicated above, these forward prices will continue to fluctuate as a result of a number of factors, including gas prices, electricity demand, which is also affected by economic growth, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered into these markets may vary materially from the forward market prices.

Into ComEd*

Into Cinergy**

(1)

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

*

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

**

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

        We intend to hedge a portion of our merchant portfolio risk through our marketing affiliate. To the extent we do not do so, the unhedged portion will be subject to the risks and benefits of spot-market price movement. The extent to which we will hedge our market price risk through forward over-the-counter sales depends on several factors. First, we will evaluate over-the-counter market prices to determine whether sales at forward market prices are sufficiently attractive compared to assuming the risk associated with spot market sales. Second, our ability to enter into hedging transactions will depend upon our liquidity and upon the over-the-counter forward sales markets' having sufficient liquidity to enable us to identify counterparties who are able and willing to enter into hedging transactions with us. Due to factors beyond our control, market liquidity has decreased significantly since the beginning of 2002, and a number of formerly significant trading parties have completely withdrawn from the market or substantially reduced their trading activities. This decrease in market

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liquidity may require us to rely more heavily on sales to end user counterparties in the direct customer markets. We are unable to predict the credit quality that such end user counterparties may have. In the event a counterparty were to default on its trade obligation, we would be exposed to the risk of possible loss associated with reselling the contracted product at a lower price if the non-performing counterparty were unable to pay the resulting liquidated damages owed to us. Further, we would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time such counterparty defaulted.

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

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

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

Non-Trading Derivative Financial Instruments

        The following table summarizes the fair values for outstanding financial instruments, based on quoted market prices, used for price risk management activities by instrument type (in thousands):

Interest Rate Risk

        Interest rate changes affect the cost of capital needed to operate the facilities and our lease costs under the Collins Station lease and the Illinois peaker power units lease.

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Off-Balance Sheet Transactions

        For a discussion of Midwest Generation, LLC's off-balance sheet transactions, refer to "Off-Balance Sheet Transactions" on page 33 of Midwest Generation, LLC's Annual Report on Form 10-K for the fiscal year ended December 31, 2001.

        On August 9, 2002, we exercised our option to purchase the Illinois peaker power units that were subject to a lease with a third-party lessor. As disclosed in "Off-Balance Sheet Transactions" in our 2001 Annual Report on Form 10-K, this operating lease was structured to maintain a minimum amount of equity (3% of the acquisition price) for the duration of the lease term in accordance with existing guidance for leases involving special purpose entities (sometimes referred to as synthetic leases). This transaction represents the only synthetic lease that we had outstanding at June 30, 2002. In order to effect the exercise of our purchase option, we obtained repayment of our $300 million loan plus interest from Edison Mission Energy and paid $300 million plus outstanding amounts due under the lease to the owner-lessor. The purchase of these peaker units will be recorded as an asset and depreciated over their estimated useful life. The annual increase to depreciation expense will be approximately $20 million.

Environmental Matters and Regulations

        For a discussion of Midwest Generation, LLC's environmental matters, refer to "Environmental Matters and Regulations" on page 33 of Midwest Generation, LLC's Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and the notes to the Financial Statements set forth therein. There have been no significant developments with regard to environmental matters that affect disclosures presented as of December 31, 2001, except as follows:

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

Critical Accounting Policies

        For a discussion of Midwest Generation, LLC's critical accounting policies, refer to "Critical Accounting Policies" on page 36 of Midwest Generation, LLC's Annual Report on Form 10-K for the fiscal year ended December 31, 2001.

New Accounting Standards

        Currently, we are using the normal sales and purchases exception for our physical coal contracts. However, in October 2001, the Derivative Implementation Group of the Financial Accounting Standards Board under Statement No. 133 Implementation Issue Number C16 precludes contracts which have variable quantities from qualifying under the normal sales and purchases exception unless these quantities are contractually limited to use by the purchaser. This implementation guidance became effective on April 1, 2002. The adoption of this implementation guidance had no impact on our financial statements.

        In August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations," which will be effective on January 1, 2003. The Statement requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the

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entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. We are studying the effects of the new standard.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        For a discussion of market risk sensitive instruments, refer to "Market Risk Exposures" on page 29 in Item 7 of Midwest Generation, LLC's Annual Report on Form 10-K for the fiscal year ended December 31, 2001. Refer to "Market Risk Exposures" in Item 2 for an update to that disclosure.

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PART II—OTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)  Exhibits

(b)  Reports on Form 8-K

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

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SIGNATURES

         Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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QuickLinks

PART I—FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
PART II—OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K