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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 333-92047-03

EME HOMER CITY GENERATION L.P.
(Exact name of registrant as specified in its charter)

Registrant's telephone number, including area code: (724) 479-9011

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

        Number of shares outstanding of the registrant's Common Stock as of August 9, 2002: Not applicable.

TABLE OF CONTENTS

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EME HOMER CITY GENERATION L.P.

BALANCE SHEETS

(In thousands)

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

1

EME HOMER CITY GENERATION L.P.

BALANCE SHEETS

(In thousands)

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

2

EME HOMER CITY GENERATION L.P.

STATEMENTS OF INCOME (LOSS)

(In thousands)

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

3

EME HOMER CITY GENERATION L.P.

STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

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

4

EME HOMER CITY GENERATION L.P.

STATEMENTS OF PARTNERS' EQUITY

(In thousands)

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

5

EME HOMER CITY GENERATION L.P.

STATEMENTS OF CASH FLOWS

(In thousands)

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

6

EME HOMER CITY GENERATION L.P.

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.

        The partnership's significant accounting policies are described in Note 2 to its financial statements as of December 31, 2001, included in its 2001 Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 1, 2002. The partnership follows the same accounting policies for interim reporting purposes, with the exception of the change in accounting for derivatives (see Note 3). This quarterly report should be read in connection with such financial statements.

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

Industry Developments

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

•

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



•

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



•

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



•

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

        We have been affected by lower wholesale prices of energy and the diminished ability to enter into forward contracts through our affiliate, Edison Mission Marketing & Trading because of credit constraints affecting Edison Mission Marketing & Trading and counterparties. See "Management's Discussion and Analysis of Results of Operations and Financial Condition—Credit Ratings."

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Note 2. Accumulated Other Comprehensive Income (Loss)

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

        Unrealized gains on cash flow hedges at June 30, 2002 primarily include forward energy sales contracts that did not meet the normal sales and purchases exception under SFAS No. 133 due to the partnership's net settlement procedures with counterparties through its marketing affiliate. The partnership began treating its forward energy sales contracts as cash flow hedges under SFAS No. 133 on April 1, 2002 as a result of the recent, revised, SFAS No. 133 Implementation Issue Number C15. See Note 3 for additional explanation on this accounting change. These gains arise because current forecasts of future electricity prices are lower than our contract prices. As our hedged positions are realized, approximately $6.0 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 a cash flow hedge is designated is one year.

        Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. The partnership recorded a net $0.6 million loss during the second quarter and six months ended June 30, 2002 representing the amount of cash flow hedges' ineffectiveness, reflected in income (loss) from price risk management in the income statement.

Note 3. Change in Accounting

        Effective April 1, 2002, the partnership implemented the Derivative Implementation Group of the Financial Accounting Standards Board's revised "Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity," referred to as Statement No. 133 Implementation Issue Number C15. This revised interpretation precludes the partnership from qualifying for the normal sales and purchases exception on its forward energy sales contracts since it has net settlement agreements with its counterparties through its marketing affiliate. Therefore, the partnership has treated its forward energy sales contracts as cash flow hedges. As a cumulative effect of adoption of this interpretation, the partnership recorded an $11.9 million increase to its net assets in the balance sheet at the fair value of its forward energy sales contracts, and $6.4 million, after tax, to accumulated other comprehensive income in the balance sheet.

Note 4. Commitments and Contingencies

Ash Disposal Site

        Pennsylvania Department of Environmental Protection, or PADEP, regulations governing ash disposal sites require, among other things, groundwater assessments of landfills if existing groundwater monitoring indicates the possibility of degradation. The assessments could lead to the installation of additional monitoring wells and if degradation of the groundwater were discovered, the partnership would be required to develop abatement plans, which may include the lining of unlined sites. To date, the facilities' ash disposal site has not shown any signs that would require abatement. Management does not believe that the costs of maintaining and abandoning the ash disposal site will have a material impact on the partnership's results of operations or financial position.

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Environmental Matters

        The partnership believes that it is in substantial compliance with environmental regulatory requirements; however, possible future developments, such as the enactment of more stringent environmental laws and regulations, could affect the costs and the manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance that the partnership would be able to recover increased costs from its customers or that its financial position and results of operations would not be materially affected.

        Prior to the partnership's purchase of the Homer City facilities, the Environmental Protection Agency requested information from the prior owners of the plant concerning physical changes at the plant. The partnership has been in informal voluntary discussions with the Environmental Protection Agency relating to these facilities, which may result in the payment of civil fines. The partnership cannot assure you that it will reach a satisfactory agreement or that these facilities will not be subject to proceedings in the future. Depending on the outcome of the proceedings, the partnership could be required to invest in additional pollution control requirements, over and above the upgrades it is planning to install, and could be subject to fines and penalties. The partnership cannot estimate the outcome of these discussions or the potential costs of investing in additional pollution control requirements, fines or penalties at this time.

Penn Hill No. 2 and Dixon Run No. 3 Discharges

        In connection with the purchase of the Homer City facilities, the partnership acquired the Two Lick Creek Dam and Reservoir. Acid mine drainage discharges from the Penn Hill No. 2 and Dixon Run No. 3 inactive deep mines were collected and partially treated on the reservoir property by Stanford Mining Company before being pumped off the property for additional treatment at the nearby Chestnut Ridge Treatment Plant. The mining company subsequently filed for bankruptcy. However, it operated the collection and treatment system until May 1999, when it ceased to do so claiming its assets were allegedly depleted.

        PADEP initially advised the partnership that it was potentially liable for treating the two discharges solely because of its ownership of the property from which the discharges emanated. Without any admission of liability, the partnership voluntarily entered into a letter agreement to fund the operation of the collection and treatment system for an interim period until the agency completed its investigation of potentially liable parties and alternatives for permanent treatment of the discharges were evaluated. After examining property records, PADEP concluded that the partnership is only responsible for treating the Dixon Run No. 3 discharge. The agency completed its investigation of other potentially responsible parties, particularly mining companies that previously operated the two mines, and has notified the partnership that it plans no further action against other parties.

        A draft consent decree agreement that addresses remedial responsibilities for the two discharges has been prepared by PADEP. Under its terms, the partnership is responsible for designing and implementing a permanent system to collect and treat the Dixon Run No. 3 discharge. The partnership will continue its funding of the existing collection and treatment system until the Dixon Run No. 3 treatment system becomes operational. The state provided funding to the Blacklick Creek Watershed Association to develop and operate a collection and treatment system for the Penn Hill No. 2 discharge. The Watershed Association has completed construction and the Penn Hill No. 2 system is in operation.

        The current cost of operating the collection and treatment system is approximately $17,000 per month. The partnership expects that the costs of operation will be reduced by 30% to 40% as a result of the completion of the Penn Hill No. 2 system. The partnership has evaluated options for permanent treatment of the Dixon Run No. 3 discharge and concluded that conventional chemical treatment is the

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most appropriate option. The capital cost of the system is estimated to be $1 million. Its operational costs cannot be determined until design and permitting are complete.

Helvetia Discharges

        The partnership's generating units were originally constructed as a mine-mouth generating station, where coal produced from two adjacent deep mines was delivered directly to the units by coal conveyors. The two adjacent deep mines were owned by Helen Mining Company, a subsidiary of the Quaker State Corporation, and Helvetia, a subsidiary of the Rochester and Pittsburgh Coal Company. Both Helen Mining and Helvetia developed mine refuse sites, water treatment facilities and other mine related facilities on the site. The Helen Mining mine was closed in the early 1990s, and the mine surface operations and maintenance shop areas were restored before Helen Mining left the site. Helen Mining has continuing mine water and refuse site leachate treatment obligations and remains obligated to perform any cleanup required with respect to its refuse site. Helvetia's on-site mine was closed in 1995. As a result of the cessation of its on-site mining activities, Helvetia has continuing mine discharge and refuse site leachate discharge treatment obligations that it performs using water treatment facilities owned by Helvetia and located on the site. Bonds posted by Helvetia may not be sufficient to fund Helvetia's obligations in the event of Helvetia's failure to comply with its mine-related permits at the site. Current annual operating costs for Helvetia's treatment systems are estimated to be approximately $1 million. If Helvetia defaults on its treatment obligations, the government may attempt to require the partnership to fund these commitments.

Plant Improvements

        The partnership has contracted with a division of ABB Flakt, now Alstom Power, to make environmental capital improvements to its generating units. The contractor was retained to construct a limestone-based, wet scrubber flue gas desulfurization system at Unit 3 and a selective catalytic reduction system at each of the three units. These improvements are expected to enable the partnership's generating units to comply with Phase II of Title IV of the Clean Air Act regarding sulfur oxide emissions, the Pennsylvania nitrogen oxide allowance regulations and Pennsylvania's response to the Environmental Protection Agency's State Implementation Plan Call regarding nitrogen oxide emissions. These improvements are estimated to cost approximately $275.5 million, which includes a fixed price, turnkey engineering, procurement and construction contract, project management costs and other project costs. The wet scrubber flue gas desulfurization system on Unit 3 has been installed and is operational. The selective catalytic reduction system on Unit 3 was installed but went out of service on February 10, 2002 due to a collapse of ductwork. Unit 3 was returned to service on April 4, 2002 and is operating with the selective catalytic reduction system bypassed. Reconnection of the selective catalytic reduction system will be implemented at a later date in accordance with an outage plan to be developed. The partnership believes that the costs to repair the damage to Unit 3 will be covered by insurance and by contractual obligations of the contractor who installed the selective catalytic reduction system. The partnership has completed a preliminary investigation of the event, and a more in-depth analysis of the root causes of the event is ongoing to determine the extent to which insurers and/or the contractor will cover the resulting costs of property damage and repair. The partnership may also be entitled to recovery of business interruption losses under one of its insurance programs, but such determination has not been made or quantified at this time.

        The selective catalytic reduction systems on Units 1 and 2 were installed. However, as a result of the Unit 3 ductwork collapse, the partnership reviewed the similar structures on Units 1 and 2 and determined that as a precaution it would be appropriate to install additional reinforcement in these structures. The additional reinforcement extended the duration of planned outages for these units, which had been scheduled to end on June 2, 2002. Unit 1 returned to service on June 28, 2002 and Unit 2 returned to service on June 26, 2002. The partnership expects to spend approximately

10

$7.9 million during the final two quarters of 2002 on capital expenditures related to this project on all three units.

Coal Cleaning Agreement

        The partnership has entered into a Coal Cleaning Agreement with Homer City Coal Processing Corp. to operate and maintain a coal cleaning plant owned by the partnership. Under the terms of the agreement, which is scheduled to expire on August 31, 2002, the partnership is obligated to reimburse Homer City Coal Processing Corp. for the actual costs incurred in the operations and maintenance of the coal cleaning plant, a fixed general and administrative service fee of $260,000 per year, and an operating fee that ranges from $.20 to $.35 per ton depending on the level of tonnage.

Interconnection Agreement

        The partnership's general partner, Mission Energy Westside, has entered into an interconnection agreement with New York State Electric & Gas Corporation, or NYSEG, and Pennsylvania Electric Company, or Penelec, to provide interconnection services necessary to interconnect the Homer City Station with NYSEG and Penelec's transmission systems. Unless terminated earlier in accordance with its terms, the interconnection agreement will terminate on a date mutually agreed to by Mission Energy Westside, NYSEG and Penelec. This date will not exceed the retirement date of the Homer City units. NYSEG and Penelec have agreed to extend such interconnection services (but not the expiration of the agreement) to modifications, additions, upgrades or repowering of the Homer City units. Mission Energy Westside is required to compensate NYSEG and Penelec for all reasonable costs associated with any modifications, additions or replacements made to NYSEG or Penelec's interconnection facilities or transmission systems in connection with any modification, addition, upgrade or repowering to the Homer City units.

Lease Swap Agreement

        In connection with the sale-leaseback transaction, the partnership entered into a swap agreement with a bank in order to more effectively match its lease payments with its cash flow, which is higher during the summer months when energy prices are usually higher. Under the terms of this swap, the partnership made an initial deposit of $37 million with the bank in December 2001. Beginning in April 2002 through April 2014, the bank will make a swap payment to the partnership in April of each year and the partnership will make a swap payment to the bank in October of each year. In April 2002, the partnership received a payment from the bank of $54.3 million, resulting in a net loan balance to the bank of $17.1 million at June 30, 2002. The amount of payments are designed to reverse the semi-annual payments due under the lease such that the partnership effectively has lower cash obligations in April and higher cash obligations in October. The partnership is also required to fund one-sixth of the October swap payment each month, between April and September of each year, into a restricted cash account. The implicit interest rate, which was fixed at inception of the swap agreement, was based on LIBOR during periods that the partnership would have a net deposit with the bank, and LIBOR plus 5% during periods that the partnership would have a net loan with the bank.

Insurance

        The partnership maintains insurance coverages consistent with those normally carried by companies engaged in similar businesses and owning similar properties. The insurance program includes all-risk real and personal property insurance, including coverage for losses from boiler and machinery breakdowns, and the perils of earthquake and flood, subject to certain sublimits. The property insurance program currently covers losses up to $750 million. Under the terms of the participation agreements entered into on December 7, 2001 as part of the sale-leaseback transaction, the partnership is required to maintain certain minimum insurance coverages. Although the insurance covering the

11

Homer City facilities is comparable to insurance coverages normally carried by companies engaged in similar businesses, and owning similar properties, the insurance coverages that are in place do not meet the minimum insurance coverages required under the participation agreements. The partnership is currently having discussions with the owner lessors to agree upon the adequacy of the insurance coverages that are in place.

        The partnership also carries general liability insurance covering liabilities to third parties for bodily injury or property damage resulting from operations, automobile liability insurance and excess liability insurance. Limits and deductibles in respect of these insurance policies are comparable to those carried by other electric generating facilities of similar size.

Collective Bargaining Agreement

        Approximately 74% of the partnership's workforce was covered by a collective bargaining agreement at June 30, 2002. The collective bargaining agreement, which also includes a benefit agreement, is due to expire on May 14, 2003.

Note 5. 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 quarterly report, 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 EME Homer City Generation L.P.'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 EME Homer City Generation L.P.

        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 EME Homer City Generation L.P. 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 EME Homer City Generation L.P.'s Annual Report on Form 10-K for the year ended December 31, 2001.

General

        We were formed on October 31, 1998 as a Pennsylvania limited partnership among Chestnut Ridge Energy Company, as a limited partner with a 99 percent interest, and Mission Energy Westside Inc., as a general partner with a 1 percent interest. Both Chestnut Ridge Energy and Mission Energy Westside are wholly-owned subsidiaries of Edison Mission Holdings Co., a wholly-owned subsidiary of Edison Mission Energy, which is an indirect wholly-owned subsidiary of Edison International. We were formed for the purpose of acquiring, owning and operating three coal-fired electric generating units and related facilities, which we refer to as the Homer City facilities, located near Pittsburgh, Pennsylvania for the purpose of producing electric energy.

        On December 7, 2001, we completed a sale-leaseback of the Homer City facilities to third-party lessors for an aggregate purchase price of $1.591 billion, made up of $782 million in cash and assumption of debt (the fair value of which was $809.3 million). This transaction has been accounted for as a lease financing for accounting purposes. In connection with the sale-leaseback transaction, our partnership agreement was amended to, among other things, change the ownership interests in us to 99.9 percent for Chestnut Ridge Energy and 0.1 percent for Mission Energy Westside.

        We derive revenue from the sale of energy and capacity into the Pennsylvania-New Jersey-Maryland Power Pool, or PJM, and the New York Independent System Operator, or NYISO, and from bilateral contracts with power marketers and load serving entities within PJM, NYISO and the surrounding markets. We have entered into a contract with a marketing affiliate for the sale of energy and capacity from our Homer City facilities, 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.

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

13

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 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

        We have been affected by lower wholesale prices of energy and the diminished ability to enter into forward contracts through our affiliate, Edison Mission Marketing & Trading because of credit constraints affecting Edison Mission Marketing & Trading and counterparties. See "—Credit Ratings."

Related Party Transactions

        During 2002, we entered into four capacity swap agreements with our marketing affiliate. Each agreement was at fair market value at the time of the transaction. Payments received under these agreements amounted to $2.3 million.

Results of Operations

Operating Revenues

        Operating revenues decreased $25.2 million and $68.2 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. Energy and capacity sales were made through contracts with our marketing affiliate. Revenues decreased primarily due to decreased generation and lower energy prices. On February 10, 2002, the ductwork and bypass associated with the selective catalytic reduction system on Unit 3 collapsed. No fire occurred and no injuries were reported as a result of the event. Unit 3 returned to service on April 4, 2002 and is operating with the selective catalytic reduction system bypassed. Reconnection of the selective catalytic reduction system will be implemented at a later date in accordance with an outage plan to be developed. We believe that the costs to repair the damage to Unit 3 will be covered by insurance and by contractual obligations of the contractor who installed the selective catalytic reduction system. We have completed a preliminary investigation of the event, and a more in-depth analysis of the root causes of the event is ongoing to determine the extent to which insurers and/or the contractor will cover the resulting costs of property damage and repair. We may also be entitled to recovery of

14

business interruption losses under one of our insurance programs, but such determination has not been made or quantified at this time.

        As a result of the Unit 3 ductwork collapse, we reviewed the similar structures on Units 1 and 2 and determined that as a precaution it would be appropriate to install additional reinforcement in these structures. The additional reinforcement extended the duration of planned outages for these units, which had been scheduled to end on June 2, 2002. Unit 1 returned to service on June 28, 2002 and Unit 2 returned to service on June 26, 2002.

        We generated 2,239 GWhr and 4,934 GWhr of electricity during the second quarter and six months ended June 30, 2002, respectively, compared to generating 2,663 GWhr and 6,160 GWhr of electricity in the corresponding periods of 2001. Our availability factor for the six months ended June 30, 2002 was 61.8%, compared to 83.3% for the corresponding period in 2001. 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 a forced outage rate of 26.2% and 3.5% during the six months ended June 30, 2002 and 2001, respectively. As described above, our Unit 3 experienced a forced outage during the first quarter of 2002, and Units 1 and 2 experienced extended outages during the second quarter of 2002.

        The weighted average price for energy was $30.68/MWh and $33.92/MWh during the second quarters of 2002 and 2001, respectively. The weighted average price for energy was $28.45/MWh and $33.64/MWh for the six months ended June 30, 2002 and 2001, respectively. The decrease was due to lower PJM market prices. See "—Market Risk Exposures—Commodity Price Risk" for further discussion of PJM market prices.

        Losses from price risk management activities increased $0.5 million and $0.6 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. In 2002, the losses primarily represent the ineffective portion of our forward energy sales contracts which are derivatives that qualified as cash flow hedges under SFAS No. 133. In 2001, a small portion of our forward power purchase and sales contracts, which were non-speculative, were recorded as derivatives at fair value under SFAS No. 133. These changes in fair value were recognized as income (loss) from price risk management.

Operating Expenses

        Operating expenses increased $5.5 million and $2.6 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. Operating expenses consisted 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 $9.2 million and $18.7 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. The decrease is due to decreased generation. The average price of delivered coal per ton was $26.50 and $27.76 during the six months ended June 30, 2002 and 2001, respectively. The change in the average price of delivered coal per ton is due to the changes in the type of coal being used in operations.

        Plant operations costs increased $10.3 million and $12.3 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. Plant operations costs include labor and overhead, contract services, parts and supplies and other administrative costs. The increases are primarily due to maintenance costs related to our forced outages as mentioned previously, increased insurance costs from higher premiums and higher estimated benefit costs. Planned maintenance expense varies based on a number of factors, including timing of our maintenance on major pieces of equipment, including the boiler and turbine on each unit, which is

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generally planned for three-year and six-year cycles. Our planned major maintenance expenditures are expected to be similar during the next several years.

        Depreciation and amortization increased $3.0 million and $6.5 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. Prior to the completion of the sale-leaseback transaction on December 7, 2001, depreciation and amortization expense primarily related to the acquisition of the Homer City facilities, which were being depreciated over 39 years from the date of acquisition. As a result of the sale-leaseback, depreciation and amortization of our leasehold interest and emission credits is based on the minimum term of the leases, which is 33.67 years.

        Administrative and general expenses increased $1.4 million and $2.5 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. Beginning in 2002, administrative and general expenses primarily include our allocated share of Edison Mission Energy's Americas Region Chicago office. The Chicago office has technical and managerial responsibility for our operations. Historically, we were not charged this allocation as the Chicago office was principally focused on Edison Mission Energy's power plants in Illinois. The allocation was recorded as a non-cash charge to our operations through an in-kind contribution of services from our partners. Administrative and general expenses also include the accrual for Pennsylvania state capital tax.

Other Income (Expense)

        Interest expense increased $8.9 million and $16.6 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. Interest expense prior to December 7, 2001 was due to the indebtedness incurred to acquire the Homer City facilities. As a result of the sale-leaseback, the increase in interest expense was primarily from the lease financing. Interest expense also included interest of $12.5 million and $33.5 million in the second quarters ended June 30, 2002 and 2001, respectively, and $24.6 million and $67.4 million in the six months ended June 30, 2002, respectively, from our subordinated loan agreements with Edison Mission Finance.

        Interest and other income increased $1.9 million and $3.7 million in the second quarter and six months ended June 30, 2002, respectively, compared to the corresponding periods of 2001. Interest and other income (expense) primarily relates to interest earned on cash and cash equivalents and fees paid to our marketing affiliate. In the second quarter of 2001, we also had approximately $2.2 million of losses related to removal of equipment in connection with our capital improvement program.

Provision (Benefit) for Income Taxes

        We had an effective tax provision (benefit) rate during the first six months of 2002 of 45.4% and 41.0% for the corresponding period of 2001. Our effective tax provision (benefit) rate varies from the federal statutory rate of 35% due to state income taxes.

Liquidity and Capital Resources

        At June 30, 2002, we had cash and cash equivalents of $62.1 million compared to $38.5 million at December 31, 2001. Net working capital at June 30, 2002 was $41.7 million compared to $87.7 million at December 31, 2001.

        Net cash provided by operating activities decreased $32.2 million in the first six months of 2002 compared to the corresponding period of 2001. The change is primarily due to our net loss and timing of cash receipts and disbursements related to working capital items.

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        Net cash used in financing activities increased $62.2 million in the first six months of 2002 compared to the corresponding period of 2001. In 2002, we borrowed less from our affiliate, received $54.1 million in principal cash payments from our swap agreement with a bank, and made a lease payment on the sale-leaseback we entered into on December 7, 2001.

        Net cash provided by investing activities increased $86.9 million in the first six months of 2002 compared to the corresponding period of 2001. In 2002, we invested less in capital expenditures and utilized some of our restricted cash to meet our lease payment obligations.

        Capital expenditures were $18.0 million and $52.3 million for the six months ended June 30, 2002 and 2001, respectively, primarily related to the addition of a flue gas desulfurization system on Unit 3 and the selective catalytic reduction systems on all three units. These capital expenditures are expected to enhance the economics of our units by reducing fuel costs, including reducing the need for purchases of nitrogen oxide and sulfur dioxide emission allowances. We expect to spend approximately $9.9 million for the remainder of 2002 on capital expenditures. Our cash generated from operations is restricted for use by the sale-leaseback agreements. Therefore, these expenditures are planned to be funded through additional loans to us under our subordinated revolving loan agreement with Edison Mission Finance.

        Under the participation agreements entered into as part of the sale-leaseback transaction, our ability to enter into specified transactions and to engage in specified business activities, including financing and investment activities, is subject to significant restrictions. These restrictions could affect, and in some cases significantly limit or prohibit, our ability to, among other things, merge, consolidate or sell our assets, create liens on our properties or assets, enter into non-permitted trading activities, enter into transactions with our affiliates, incur indebtedness, create, incur, assume or suffer to exist guarantees or contingent obligations, make restricted payments to our partners, make capital expenditures, own subsidiaries, liquidate or dissolve, engage in non-permitted business activities, sublease our leasehold interests in the facilities or make improvements to the facilities. Accordingly, our liquidity is substantially based on our ability to generate cash flow from operations. If we are unable to generate cash flow from operations necessary to meet our obligations, we will have limited ability to obtain additional capital, unless our partners provide additional funding, which they are under no legal obligation to do.

        Our bank accounts are largely under the control of a collateral agent that operates in accordance with a security deposit agreement executed as part of the sale-leaseback transaction. Accordingly, our access to most of the cash in our bank accounts is limited to specific uses set forth in this agreement. The rent payments that we owe under the sale-leaseback are comprised of two components, a senior rent portion and an equity rent portion. The senior rent is used mainly for debt service to the holders of the senior secured bonds, while the equity rent is paid to the owner lessors. In order to pay the equity portion of the rent, we are required to meet a projected senior rent service coverage ratio of 1.7 to 1.0 for periods after December 31, 2001 subject to reduction to 1.3 to 1.0 under circumstances specified in the participation agreements. The senior rent coverage ratio is determined by dividing net cash flow as defined in the participation agreements by the senior rent due in that period. If we do not meet specified cash flow coverage ratios while the lease debt is outstanding, we will not pay the equity portion of the rent to the owner lessors. Accordingly, this provision does not permit the lessor to terminate the lease in the event of non-payment of the equity portion of the rent while the lease debt is outstanding.

Credit Ratings

        We are not currently rated. However, we have entered into a contract with a marketing affiliate, Edison Mission Marketing & Trading, for the sale of energy and capacity from our facilities, which enables this marketing affiliate to engage in forward sales and hedging. Under this contract, we pay the

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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. In addition, Standard & Poor's changed its outlook to negative from stable on its "BBB-" rating on the lessor bonds related to the sale-leaseback of our facilities.

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

Market Risk Exposures

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

Commodity Price Risk

        Our revenues and results of operations are dependent upon prevailing market prices for energy, capacity, emission credits and ancillary services in the PJM, NYISO and other competitive markets. The following table depicts the average market prices per megawatt hour in PJM during the first six months of 2002 and 2001:

*

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

        As shown on the above table, the average historical market prices during the first six months of 2002 are below the average historical market prices during the first six months of 2001. The forward market prices in PJM fluctuate as a result of a number of factors, including gas prices, electricity

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demand which is also affected by economic growth, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered into these markets may vary materially from the forward market prices. At the end of July 2002, our forecasted yearly average 24-hour PJM prices for 2002 was $25.31, compared to the actual yearly average 24-hour PJM prices of $29.07 in 2001. Our forecasted yearly average 24-hour PJM prices are based on year-to-date actual data and a forecast for the remainder of the year based on current market information.

        The following table sets forth the forward month-end market prices for energy per megawatt hour for the calendar 2003 and calendar 2004 "strips", which are defined as energy purchases for the entire calendar year, for sales in PJM during the first six months of 2002.

*

Prices were obtained by gathering publicly available broker quotes.

        Among the factors that may influence future market prices for energy, capacity and ancillary services in PJM and NYISO 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 PJM and/or NYISO;



•

the extended operation of nuclear generating plants in PJM and NYISO beyond their presently expected dates of decommissioning;



•

weather conditions prevailing in PJM and NYISO 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.

        Our ability to make payments of lease rent on the facility leases depends on revenues generated by the facilities, which depend on their performance level and on market conditions for the sale of capacity and energy. These market conditions are beyond our control.

        Our risk management policy allows for the use of derivative financial instruments through our marketing affiliate to limit financial exposure to energy prices for non-trading purposes. Use of these instruments exposes us to commodity price risk, which includes potential losses that can arise from a change in the market value of a particular commodity. Commodity price risk exposures are actively monitored to ensure compliance with our risk management policies. Policies are in place which limit the amount of total net exposure we may enter into at any point in time. Procedures and systems are in place that allow for monitoring of all commitments and positions with daily reporting to senior management. Our marketing affiliate performs a series of "value at risk" analyses in our daily business to measure, monitor and control our overall market risk exposure. The use of value at risk analysis allows us to aggregate overall risk, compare risk on a consistent basis and identify the different elements of risk. Value at risk measures the worst expected loss over a given time interval, under

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normal market conditions, at a given confidence level. Given the inherent limitations of value at risk analysis and reliance upon a single risk measurement tool, our marketing affiliate supplements this approach with the use of stress testing and worst-case scenario analysis, as well as stop loss limits and counterparty credit exposure monitoring.

        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

        We have mitigated the risk of interest rate fluctuations by obtaining fixed rate financing on our outstanding long-term debt with our affiliate. We do not believe that interest rate fluctuations will have a materially adverse effect on our financial position or results of operations.

Environmental Matters and Regulations

        For a discussion of EME Homer City Generation L.P.'s environmental matters, refer to "Environmental Matters and Regulations" on page 28 of EME Homer City Generation L.P.'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.

Critical Accounting Policies

        For a discussion of EME Homer City Generation L.P.'s critical accounting policies, refer to "Critical Accounting Policies" on page 33 of EME Homer City Generation L.P.'s Annual Report on Form 10-K for the fiscal year ended December 31, 2001.

New Accounting Standards

        In December 2001, the Derivative Implementation Group of the Financial Accounting Standards Board issued a revised interpretation of "Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity," referred to as Statement No. 133 Implementation Issue Number C15. Under this revised interpretation, our forward electricity contracts no longer qualify for the normal sales exception since our marketing affiliate has net settlement agreements with their counterparties. In lieu of following this exception in which we record revenue on an accrual basis, we believe our forward sales agreements qualify as cash flow hedges. Under a cash flow hedge, we record the fair value of the forward sales agreements on our balance sheet and record the effective portion of the cash flow hedge as part of other comprehensive income. The ineffective portion of our cash flow hedges is recorded directly in our income statement. We implemented this interpretation on April 1, 2002. We recorded assets at fair value of $11.9 million, deferred taxes of $5.5 million and a $6.4 million increase to other comprehensive income as the cumulative effect of adoption of this interpretation.

        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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        For a discussion of market risk sensitive instruments, refer to "Market Risk Exposures" on page 24 of EME Homer City Generation L.P.'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 reports 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