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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2001

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

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:
8.137% Senior Secured Bonds due 2019
8.734% Senior Secured Bonds due 2026
(Title of Class)

        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

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K o.

        Aggregate market value of the registrant's common equity held by non-affiliates of the registrant as of March 28, 2002: $0. Number of shares outstanding of the registrant's Common Stock as of March 28, 2002: Not applicable.

TABLE OF CONTENTS

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PART I

ITEM 1. BUSINESS

The Company

        We were formed on October 31, 1998 as a Pennsylvania limited partnership with 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 located near Pittsburgh, Pennsylvania with an aggregate capacity of 1,884 megawatts, or MW, which we collectively refer to as the facilities, for the purpose of producing electric energy. Although we were formed on October 31, 1998, we had no significant activity prior to the acquisition of the facilities.

        On December 7, 2001, we completed a sale-leaseback of our facilities to third-party lessors for an aggregate purchase price of $1.591 billion, made up of $782 million in cash and the assumption of the obligations under our 8.137% Senior Secured Bonds due 2019 and 8.734% Senior Secured Bonds due 2026, which we refer to collectively as the senior secured bonds (the fair value of which was $809.3 million). Our transaction has been accounted for as a lease financing for accounting purposes. We registered pass-through bonds with the Securities and Exchange Commission and the holders of the senior secured bonds agreed to exchange the senior secured bonds for the pass-through bonds, in order to consummate the transaction. In connection with the transaction, we have been released from our guarantee on the senior secured bonds, but we remain indirectly liable to make payments on the pass-through bonds, through our semi-annual lease payments. Also, in connection with the transaction, the partnership agreement was amended to, among other things, change our ownership interests to 99.9 percent for Chestnut Ridge Energy and 0.1 percent for Mission Energy Westside. For more information on the sale-leaseback transaction, see "Notes to Financial Statements—Note 3. Sale-Leaseback Transaction."

        Edison Mission Energy is our indirect parent company. Edison Mission Energy's ultimate parent company is Edison International, which also owns Southern California Edison, one of the largest electric utilities in the United States. Each of these companies is registered with the Securities and Exchange Commission and has financial statements that are filed in accordance with rules enacted by the Securities and Exchange Commission. For more information regarding each of these companies, see their respective Form 10-K for the year ended December 31, 2001.

        The address of our principal executive offices is 1750 Power Plant Road, Homer City, Pennsylvania, 15748-8009 and our telephone number is (724) 479-9011.

Forward-Looking Statements

        This annual report includes forward-looking statements. We have based these forward-looking statements on our current expectations and projections about future events based upon our knowledge of facts as of the date of this annual report and our assumptions about future events. These forward-looking statements are subject to various risks and uncertainties that may be outside our control, including, among other things:

•

governmental, statutory, regulatory or administrative changes or initiatives affecting us, our facilities or the United States electricity industry generally;



•

supply, demand and price for electric capacity and energy in the markets served by our generating units;

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•

competition from other power plants, including new plants that may be developed in the future;



•

operating risks, including equipment failure, dispatch levels, availability, heat rate and output; and



•

the cost, availability and pricing of fuel and fuel transportation services for our facilities.

        We use words like "believe," "expect," "anticipate," "intend," "may," "will," "should," "estimate," "projected" and similar expressions to help identify forward-looking statements in this annual report. For additional factors that could affect the validity of our forward-looking statements, you should read "Management's Discussion and Analysis of Results of Operations and Financial Condition" contained in Part II, Item 7 and the "Notes to Financial Statements" contained in Part II, Item 8. The information contained in this report is subject to change without notice. Readers should review future reports filed by us with the Securities and Exchange Commission. In light of these and other risks, uncertainties and assumptions, actual events or results may be very different from those expressed or implied in the forward-looking statements in this annual report or may not occur. We have no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Description of Business

Industry Overview

        The United States electric industry, including companies engaged in providing generation, transmission, distribution and ancillary services, has undergone significant change over the last several years, leading to significant deregulation and increased competition. The Federal Energy Regulatory Commission, under Order No. 888 and Order No. 889, which are referred to as the Open Access Rules, requires the owners and operators of electric transmission facilities to make those facilities available for transmission on a non-discriminatory basis to all wholesale generators, sellers and buyers of electricity. In addition to this wholesale transmission, or wheeling, throughout the United States, there has been a number of proposals at the state level to allow retail customers to choose their electricity suppliers, with incumbent utilities required to deliver that electricity over their transmission and distribution systems. Numerous electric utilities nationwide have divested all or a portion of their electricity generation business as legislative and regulatory developments have driven the industry to disaggregate. We, through Edison Mission Energy and its other subsidiaries, are among a group of companies actively pursuing opportunities created by the deregulating domestic electric markets to operate as competitive electric generation and wholesale supply companies in a deregulated marketplace.

Power Markets

        PJM.    The Pennsylvania - New Jersey - Maryland Power Pool, or PJM, is the largest centrally dispatched electric control area in North America and the third largest in the world, consisting of over 540 generating units with a total installed capacity of 57,000 MW. PJM serves 8.7% of the United States population and covers portions of Pennsylvania, New Jersey, Maryland, Delaware, the District of Columbia and Virginia. PJM was restructured in April 1997 as a competitive, non-discriminatory market in response to the Open Access Rules and includes bid-based energy and capacity markets. The independent system operator for the PJM operates the spot energy market and determines the market-clearing price for each hour based on bids submitted by participating generators which indicate the minimum prices a bidder is willing to accept to be dispatched at various incremental generation levels. PJM conducts both day-ahead and real-time energy markets. A transmission charge based on the location of the energy purchaser is added to the energy price if the transmission system becomes constrained and generators with higher bids are dispatched prior to those with lower bids. To ensure that sufficient capacity is available in the market to meet reliability standards, PJM has a day-ahead

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installed capacity market and monthly installed capacity markets extending twelve months in the future. Each installed capacity market has a single market-clearing price for each day during which the market is in operation.

        NYISO.    The New York Independent System Operator, or NYISO, includes 35,627 MW of installed capacity and serves over 99% of New York State's electric power requirements. The NYISO was established in 1999 as a competitive, non-discriminatory market in response to the Open Access Rules and includes bid-based electricity and transmission usage markets. The market-clearing price for NYISO's day-ahead and real-time energy markets is set by supplier generation bids and customer demand bids.

        We can transmit 1,884 MW from our generating units into NYISO through two 345 kilovolts, or kV, high voltage transmission lines and can transmit 1,884 MW into PJM through two 230 kV lines. We do not incur any access or wheeling charges for any energy delivered into PJM. A 13-mile 230 kV line from our generating units also provides an indirect interconnection to the East Central Area Reliability Council, one of the largest regional electricity markets in the United States.

Facility Overview

        We believe we are among the lowest cost generating facilities in the Northeast region of the United States. In 2001, our units had fuel expenses and operating and maintenance costs of approximately $18.32/MWh, and, in our belief, are among the first coal-fired units to be called upon for the dispatch of electric power within both PJM and NYISO. Our facilities are located on a 2,413-acre site approximately 45 miles northeast of Pittsburgh within Indiana County, Pennsylvania. Our facilities consist of the generating units, a coal cleaning facility, water supply provided by a reservoir known as the Two Lick Dam and associated support facilities. Our generating units benefit from direct transmission access to both PJM and NYISO through four high voltage lines which interconnect through a switchyard located on the site.

        Our units are coal-fired boiler and steam generating units. Units 1 and 2, which are essentially identical to one another, were constructed as positive pressure units, which utilize boilers with internal air pressure slightly higher than atmospheric pressure, and were placed into commercial operation in 1969. Units 1 and 2 were converted to balanced draft units, which utilize boilers with internal air pressure balanced at approximately atmospheric pressure, in 1976 and 1977, respectively. Unit 1 has an installed capacity of 620 MW, and Unit 2 has an installed capacity of 614 MW. The steam turbines and generators for Units 1 and 2 were manufactured by Westinghouse Electric Corporation, and the boilers for these units were manufactured by Foster Wheeler Energy Corporation. The Unit 1 and 2 boilers have been retrofitted with Foster Wheeler dual air register and internal flame staging low nitrogen oxide burners to meet Phase I nitrogen oxide Clean Air Act standards. See "Management's Discussion and Analysis of Results of Operations and Financial Condition—Environmental Matters and Regulations—Federal—United States of America—Clean Air Act." In addition, both boilers have supplemental over-fired air systems to further reduce nitrogen oxide emissions to satisfy Pennsylvania Title I (ozone) requirements.

        Unit 3 commenced commercial operation in 1977 and has an installed capacity of 650 MW. The steam turbine and generator for Unit 3 were manufactured by General Electric Corporation, and the Unit 3 boiler was manufactured by Babcock & Wilcox. The boiler for Unit 3 was originally constructed with Babcock & Wilcox low nitrogen oxide burners which satisfied Phase I nitrogen oxide Clean Air Act standards, and a supplemental over-fired air system was installed in 1995 at Unit 3 to further reduce nitrogen oxide emissions. In 2001, a wet scrubber flue gas desulfurization system and a selective catalytic reduction system was installed on Unit 3. These improvements are expected to enable our generating unit 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

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Environmental Protection Agency's State Implementation Plan Call regarding nitrogen oxide emissions. On February 10, 2002, the ductwork and bypass associated with the selective catalytic reduction system collapsed. For further discussion of this event, see "Management's Discussion and Analysis of Results of Operations and Financial Condition—Recent Developments."

        Emission allowances were acquired by us as part of the acquisition of the facilities. Emission allowances are required by our facilities in order to be certified by the local environmental authorities and are required to be maintained throughout the period of operation of the facilities. We purchase additional emission allowances when necessary to meet environmental regulations. We also use forward sales and purchases, together with options, to achieve our objective of stabilizing and enhancing the operations from our facilities.

Sales Strategy

        We sell capacity, energy and voltage support from our units into PJM's and NYISO's centralized power markets. We believe that our units comprise the second largest coal-fired facility within PJM and the largest coal-fired facility servicing NYISO. We may also enter into bilateral contracts for the sale of capacity and energy to power marketers and load serving entities within PJM, NYISO and surrounding markets.

        Marketing and Trading.    We have entered into a contract with a marketing affiliate for the sale of energy and capacity produced by our units, which enables this marketing affiliate to engage in forward sales and hedging transactions to manage our electricity price exposure. The terms of the documents relating to the sale-leaseback do not permit us to take speculative futures positions. Our marketing affiliate is required to make sales only to entities which have an investment grade rating or whose obligations are guaranteed by an entity with an investment grade rating.

        The marketing organization of our marketing affiliate is divided into front-, middle- and back-office segments, with some duties segregated for control purposes. The risk management personnel have a high level of knowledge of utility operations, fuels procurement, energy marketing and futures and options trading. The marketing affiliate has systems in place that monitor real-time spot and forward pricing, performs option valuations and has a wholesale power-scheduling group that operates on a 24-hour basis. We pay the marketing affiliate fees of $0.02/MWh plus emission allowance fees. The net fees earned by the marketing affiliate were $0.9 million, $1.5 million and $0.2 million for the years ended December 31, 2001, 2000 and 1999, respectively.

Fuel Supply

        Units 1 and 2.    Units 1 and 2 typically consume approximately 4,200,000 tons of mid-range sulfur coal per year. Approximately 90% to 95% of this coal is obtained under contracts with local suppliers within approximately 100 miles of our facilities, and the remainder is purchased in the spot market. All of this coal is delivered to the site by truck.

        The coal purchased for consumption by Units 1 and 2 is cleaned in our coal cleaning facility, which has the capacity to clean up to 5,000,000 tons of coal per year. Our coal cleaning facility utilizes heavy media cyclones, froth flotation and spiral separators to reduce the ash and sulfur content of the raw coal to meet both combustion and environmental requirements. Our coal cleaning facility is operated by Homer City Coal Processing Corporation under a coal cleaning agreement, dated August 8, 1990, which is scheduled to expire on August 31, 2002. Under the terms of the agreement, we are 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.

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        Unit 3.    Unit 3 typically consumes approximately 1,600,000 tons of compliance coal per year. We purchase approximately 75% of this coal from one supplier and that coal is blended at a coal blending facility owned by the supplier on our site. We obtain the remainder of the coal needed for Unit 3 in the spot market. All coal purchased for Unit 3 is delivered to the site by truck. A wet scrubber flue gas desulfurization system for Unit 3 was installed in 2001, which enables this unit to be able to burn less expensive, higher sulfur coal, while still meeting environmental standards for emission control.

        Our contractual commitments for the purchase of coal, subject to adjustment, are currently estimated to aggregate $472 million over the duration of the existing contracts, summarized as follows: $160 million in 2002; $99 million in 2003; $90 million in 2004; $67 million in 2005; $40 million in 2006; and $16 million thereafter.

Environmental Capital Improvements

        We have contracted with a division of ABB Flakt, now Alstom Power, to make environmental capital improvements to our 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 our 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 $270 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 undergoing acceptance testing. 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. See "Management's Discussion and Analysis of Results of Operations and Financial Condition—Recent Developments" for further discussion of this event. The selective catalytic reduction system on Units 1 and 2 are scheduled to be installed in 2002. We expect to spend approximately $17.8 million during 2002 on the remaining capital expenditures related to these improvements.

Operating Performance

        Our generating units have historically had high equivalent availability, which is the ratio, expressed as a percentage, of the amount of production that each unit was able to produce during a given time period divided by the amount of production that each unit would have produced if it operated at its full capacity during that given time period. Our generating units have also historically had efficient heat rates and low costs. The following charts indicate selected historical operating data for our generating units.

*

Data provided by prior owner of the facilities.

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Operation and Maintenance

        Our operating and maintenance plan, as well as several planned overhauls of major equipment and controls, are consistent with our goal of extending the remaining life of the units for an additional 39 years from the date we acquired them. We utilize a state-of-the-art computerized maintenance system to plan and schedule all maintenance activities. We also employ a preventative maintenance program complemented by new predictive maintenance technologies such as ferrography, thermography, vibration analysis and acoustic analysis. Reliability-centered maintenance techniques are currently being developed for critical systems to better define condition-monitoring parameters and redefine maintenance strategies.

        Our employees provide engineering, maintenance, operation and facility management services to Edison Mission Energy's affiliates and will receive functional direction from, and are held to the operating standards and guidelines of, Edison Mission Energy's operation and maintenance organization.

Transmission and Interconnection

        Existing transmission lines leaving our generating units are interconnected with both PJM and NYISO. We are able to transmit into PJM full plant output of up to 1,884 MW through a 126-mile 345 kV line and 19-mile and 15-mile 230 kV lines owned by Pennsylvania Electric Company, which we refer to as Penelec. We have the ability to transmit into NYISO full plant output of up to 1,884 MW through 175-mile and 207-mile 345 kV lines owned by New York State Electric & Gas Corporation, which we refer to as NYSEG. In addition, a 13-mile 230 kV line from our generating units provides an indirect interconnection to the East Central Area reliability market.

        The points of interconnection with our units include:

(1)

the 230 kV circuit from the Unit 1 main power transformer,



(2)

the 345 kV circuit from the Unit 2 main power transformer,



(3)

the 345 kV circuit from the Unit 3 main power transformer,



(4)

the 345/230/23 kV north and south autotransformers, and



(5)

substation services No. 1 and No. 2.

        The ownership of the transmission and distribution assets for our facilities, including the site switchyard, substation and support equipment, remained with Penelec and NYSEG following our acquisition of the facilities. These companies have agreed to provide us with all services necessary to interconnect our generating units with their transmission systems, other than services provided under existing tariffs, under an interconnection agreement, as described below.

        Our general partner, Mission Energy Westside, has entered into an interconnection agreement with NYSEG and 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.

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Water Supply and Other Support Facilities

        Our generating units receive their water supply from Two Lick Creek. The water supply to Two Lick Creek is regulated by releases from Two Lick Dam, which is located approximately eight miles upstream from our generating units and is owned, operated and maintained by us in accordance with a dam safety permit and a drought management plan and related consent order and agreement with the Pennsylvania Department of Environmental Protection. These facilities were not sold to third parties as part of the sale-leaseback transaction. Each of our generating units has a natural draft-cooling tower. A portion of the waste heat in the water leaving the units' condensers is diverted from these towers to a 14-acre polyethylene roofed greenhouse complex located adjacent to our units. After the water passes through this greenhouse complex, it is returned to the basin of the cooling towers for reuse.

        Other support facilities located on the site include an ash disposal area, a coal refuse disposal area, coal receiving and storage facilities and water treatment and pumping facilities.

Insurance

        We maintain 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 $1.25 billion. Under the terms of the facility leases, we are required to provide property insurance, if commercially available at reasonable prices, for the termination value amounts included in the facility leases. In the current market environment, insurance for the full termination value may not be available at reasonable prices, but we will continue to monitor developments in the property insurance marketplace.

        We also carry 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.

Seasonality

        Due to warmer weather during the summer months, electric revenues are usually higher during the third quarter of each year.

Tax Sharing Agreements

        We are included in the consolidated federal income tax and combined state franchise tax returns of Edison International. We calculate our income tax provision on a separate company basis under a tax sharing arrangement with Edison Mission Energy, which in turn has a tax sharing agreement with Mission Energy Holdings Company, which in turn has a tax sharing agreement with The Mission Group, which in turn has an agreement with Edison International. Tax benefits generated by us and used in the Edison International consolidated tax return are recognized by us without regard to separate company limitations.

Competition

Federal

        The Energy Policy Act of 1992 laid the groundwork for a competitive wholesale market for electricity. Among other things, the Energy Policy Act expanded the Federal Energy Regulatory Commission's authority to order electric utilities to transmit, or wheel, third-party electricity over their transmission lines, thus allowing qualifying facilities under the Public Utility Regulatory Policies Act of

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1978, power marketers and those qualifying as exempt wholesale generators under the Public Utility Holding Company Act of 1935 to more effectively compete in the wholesale market.

        In April 1996, the Federal Energy Regulatory Commission issued the Open Access Rules, which require utilities to offer eligible wholesale transmission customers non-discriminatory open access on utility transmission lines on a comparable basis to the utilities' own use of the lines. In addition, the Open Access Rules directed the regional power pools that control the major electric transmission networks to file uniform, non-discriminatory open access tariffs. On March 4, 1997, the Federal Energy Regulatory Commission issued Order No. 888-A, reaffirming its basic determinations in Order No. 888, promoting wholesale competition through open access non-discriminatory transmission services by public utilities.

        In December 1999, the Federal Energy Regulatory Commission issued Order No. 2000, which required all transmission-owning utilities to file by December 15, 2000, a statement of their plans with respect to placing their transmission assets under a Regional Transmission Organization, or RTO, meeting certain criteria set forth in the Order. Although Order No. 2000 did not mandate that a utility join an RTO, it set forth various incentives for voluntary action by utilities to take such action and required them to explain in detail their reasons for deviating from the objectives set forth in the Order. RTOs meeting the Commission's criteria in Order No. 2000 were required to be operationally independent of the transmission-owning utilities whose assets they controlled and to possess other essential attributes, such as regional scope and configuration, the authority to receive and rule upon requests for service, a separate tariff governing all transactions of the RTO, a market monitoring capability, and other features. In subsequent orders, the Commission has progressively tightened its policies in favor of RTO formation, by such means as an explicit proposal that approvals of market-based rate authority for affiliates of utilities owning transmission should be tied to such utilities' placing their transmission assets in an RTO meeting the criteria of Order No. 2000. These and other regulatory initiatives by the Federal Energy Regulatory Commission are continuing to unfold at the present time, and it is not possible to predict how far or how fast they will go. However, the direction of regulatory policy at such Commission at the present time appears generally positive for continued progress toward competitive wholesale electricity markets.

        Over the past few years, Congress has considered various pieces of legislation to restructure the electric industry which would require, among other things, customer choice, repeal of the Public Utility Holding Company Act and of the Public Utility Regulatory Policies Act. In January 2001, President Bush appointed a Cabinet level task force, headed by Vice President Cheney, to examine long-term energy policy. The task force was prompted in part by the California power crisis and its potential effect on neighboring states and other parts of the U.S. economy. The task force is charged with exploring ways to develop new sources of energy. It is unclear at this time, however, to what extent, if any, legislative or regulatory actions may result from this task force. Congress may also conduct hearings on the issue of long-term energy security.

State

        The Energy Policy Act did not preempt state authority to regulate retail electric service. Historically, in most states, competition for retail customers is limited by statutes or regulations granting existing electric utilities exclusive retail franchises and service territories. Since the passage of the Energy Policy Act, the advisability of retail competition has been the subject of intense debate in federal and state legislative and regulatory forums. Many states have taken steps to facilitate retail competition as a means to stimulate competitive generation rates. Retail competition commenced in New York in 1998. Retail competition in Pennsylvania commenced on January 1, 1999.

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Regulatory Matters

General

        Federal laws and regulations govern, among other things, transactions by and with purchasers of power, including utility companies, the operations of a project and the ownership of a project. Under limited circumstances where exclusive federal jurisdiction is not applicable or specific exemptions or waivers from state or federal laws or regulations are otherwise unavailable, federal and/or state utility regulatory commissions may have broad jurisdiction over non-utility owned electric power plants. Energy-producing projects are also subject to federal, state and local laws and regulations that govern the geographical location, zoning land use and operation of a project. Federal, state and local environmental requirements generally require that a wide variety of permits and other approvals be obtained before the commencement of construction or operation of an energy-producing facility and that the facility then operate in compliance with these permits and approvals.

        While we believe the requisite approvals for our existing facilities have been obtained and that our business is operated in substantial compliance with applicable laws, we remain subject to a varied and complex body of laws and regulations that both public officials and private parties may seek to enforce. Regulatory compliance for the construction of new facilities is a costly and time-consuming process. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures and may create a significant risk of expensive delays or significant loss of value in a project if the project is unable to function as planned due to changing requirements or local opposition.

State Energy Regulation

        State public utility commissions have broad jurisdiction over non-qualifying facility independent power projects, including exempt wholesale generators, which are considered public utilities in many states. This jurisdiction often includes the issuance of certificates of public convenience and necessity and/or other certifications to construct, own and operate a facility, as well as the regulation of organizational, accounting, financial and other corporate matters on an ongoing basis. Qualifying facilities may also be required to obtain these certificates of public convenience and necessity in some states.

        Some states that have restructured their electric industries require generators to register to provide electric service to customers. Many states are currently undergoing significant changes in their electric statutory and regulatory frameworks that result from restructuring the electric industries that may affect generators in those states. Although the Federal Energy Regulatory Commission generally has exclusive jurisdiction over the rates charged by a non-qualifying facility independent power project to its wholesale customers, a state's public utility commission has the ability, in practice, to influence the establishment of these rates by asserting jurisdiction over the purchasing utility's ability to pass-through the resulting cost of purchased power to its retail customers. A state's public utility commission also has the authority to determine avoided costs for qualifying facilities and regulate the retail rates charged by qualifying facilities. In addition, states may assert jurisdiction over the siting and construction of independent power projects and, among other things, the issuance of securities, related party transactions and the sale or other transfer of assets by these facilities. The actual scope of jurisdiction over independent power projects by state public utility commissions varies from state to state.

        In addition, state public utility commissions may seek to modify, suspend or terminate a qualifying facility's power sales contract under specified circumstances. This could occur if the state public utility commission were to determine that the pricing mechanism of the power sales contract is unfairly high in light of the current prevailing market cost of power for the utility purchasing the power. In this instance, the state public utility commission could attempt to alter the terms of the power sales contract to reflect more accurately market conditions for the prevailing cost of power. While we believe that these attempts are not common and that the state public utility commission may not have any

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jurisdiction to modify the terms of the wholesale power sales, we cannot assure you that the power sales contracts of our operations will not be subject to adverse regulatory actions.

        Pennsylvania.    Under the Pennsylvania Public Utility Law, the Pennsylvania Public Utility Commission regulates all "public utilities" operating in Pennsylvania. A "public utility" under this law includes any entity that owns or operates equipment or facilities for the production, generation, transmission or distribution of gas, electricity or steam for the production of light, heat or power to the public for consumption. The Pennsylvania Public Utility Law does not specifically address the utility status of entities selling electricity at wholesale within Pennsylvania. Because of our status as such an entity that sells electricity exclusively in the wholesale market and does not hold itself out to the public generally as a supplier of utility service, we are not likely to be regulated as a public utility under the Pennsylvania Public Utility Law. If, however, we were deemed to be a Pennsylvania public utility, the Pennsylvania Public Utility Commission could retroactively apply several provisions of the Pennsylvania Public Utility Law to us. One of those provisions requires every public utility to obtain a certificate of public convenience and necessity from the Pennsylvania Public Utility Commission prior to rendering service as a public utility. If the Pennsylvania Public Utility Commission were to require us to obtain a certificate of public convenience and necessity, we might be required to discontinue operation of our units pending application for, and receipt of, this certificate. Another provision requires every public utility to obtain Pennsylvania Public Utility Commission approval before it issues or guarantees securities. If we were found to be a public utility, our failure to have obtained this approval could call into question the validity of our obligations under the documents entered into in connection with the sale-leaseback. In addition, we would be subject to other laws and regulations, other than rate regulation, applicable to Pennsylvania public utilities. Our rates, however, would remain subject to the jurisdiction of the Federal Energy Regulatory Commission.

        New York.    Under the New York Public Service Law, the New York Public Service Commission regulates all public utility companies or utility companies operating in New York. A public utility company or utility company under the New York Public Service Law includes, among other things, any entity engaged in the production, transmission or distribution of electricity to the public for light, heat or power purposes. We, as an exempt wholesale generator, will not provide electricity directly to the public and plan to sell only to power marketers and energy service companies. Although the New York Public Service Law is silent with respect to the utility status of electric corporations selling electricity wholesale within New York, we will not likely be subject to regulation as a New York public utility. If, however, we were deemed to be a public utility under the New York Public Service Law, the New York Public Service Commission could retroactively apply specified provisions of the statute to us. We would also be subject to other laws and regulations, other than rate regulation, applicable to New York public utility companies. Our rates, however, would remain subject to the jurisdiction of the Federal Energy Regulatory Commission.

U.S. Federal Energy Regulation

Overview

        The Federal Energy Regulatory Commission has ratemaking jurisdiction and other authority with respect to interstate sales and transmission of electric energy under the Federal Power Act and with respect to certain interstate sales, transportation and storage of natural gas under the Natural Gas Act of 1938. The Securities and Exchange Commission has regulatory powers with respect to upstream owners of electric and natural gas utilities under the Public Utility Holding Company Act of 1935. The enactment of the Public Utility Regulatory Policies Act of 1978 and the adoption of regulations thereunder by the Federal Energy Regulatory Commission provided incentives for the development of cogeneration facilities and small power production facilities utilizing alternative or renewable fuels by establishing certain exemptions from the Federal Power Act and the Public Utility Holding Company Act for the owners of qualifying facilities. The passage of the Energy Policy Act in 1992 further

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encouraged independent power production by providing additional exemptions from the Public Utility Holding Company Act for exempt wholesale generators and foreign utility companies.

        An "exempt wholesale generator" under the Public Utility Holding Company Act is an entity determined by the Federal Energy Regulatory Commission to be exclusively engaged, directly or indirectly, in the business of owning and/or operating specified eligible facilities and selling electric energy at wholesale or, if located in a foreign country, at wholesale or retail.

        The Federal Power Act.    The Federal Power Act grants the Federal Energy Regulatory Commission exclusive ratemaking jurisdiction over wholesale sales of electricity in interstate commerce, including ongoing as well as initial rate jurisdiction. This jurisdiction allows the Federal Energy Regulatory Commission to revoke or modify previously approved rates. These rates may be based on a cost-of-service approach or, in geographic and product markets determined by the Federal Energy Regulatory Commission to be workably competitive, may be market based. As noted, most qualifying facilities are exempt from the ratemaking and several other provisions of the Federal Power Act. Exempt wholesale generators and other non-qualifying facility independent power projects are subject to the Federal Power Act and to Federal Energy Regulatory Commission's ratemaking jurisdiction thereunder, but the Federal Energy Regulatory Commission typically grants exempt wholesale generators the authority to charge market-based rates as long as the absence of market power is shown. In addition, the Federal Power Act grants the Federal Energy Regulatory Commission jurisdiction over the sale or transfer of jurisdictional facilities, including wholesale power sales contracts, and in some cases jurisdiction over the issuance of securities or the assumption of specified liabilities and some interlocking directorates. In granting authority to make sales at market-based rates, the Federal Energy Regulatory Commission typically also grants blanket approval for the issuance of securities and partial waiver of the restrictions on interlocking directorates.

        We are subject to the Federal Energy Regulatory Commission ratemaking regulation under the Federal Power Act. In addition, the Federal Energy Regulatory Commission's order, as is customary with market-based rate schedules, reserved the right to revoke our market-based rate authority on a prospective basis if it is subsequently determined that we or any of our affiliates possess excessive market power. If the Federal Energy Regulatory Commission were to revoke our market-based rate authority, it would be necessary for us to file, and obtain Federal Energy Regulatory Commission acceptance of, our rate schedule as a cost-of-service rate schedule. In addition, the loss of market-based rate authority would subject us to the accounting, record keeping and reporting requirements that are imposed on utilities with cost-based rate schedules.

        The Public Utility Holding Company Act.    Unless exempt or found not to be a holding company by the Securities and Exchange Commission, a company that falls within the definition of a holding company must register with the Securities and Exchange Commission and become subject to Securities and Exchange Commission regulation as a registered holding company under the Public Utility Holding Company Act. "Holding company" is defined in Section 2(a)(7) of the Public Utility Holding Company Act to include, among other things, any company that owns 10% or more of the voting securities of an electric utility company. "Electric utility company" is defined in Section 2(a)(3) of the Public Utility Holding Company Act to include any company that owns facilities used for generation, transmission or distribution of electric energy for resale. Exempt wholesale generators and foreign utility companies are not deemed to be electric utility companies, and qualifying facilities are not considered facilities used for the generation, transmission or distribution of electric energy for resale. Securities and Exchange Commission precedent also indicates that it does not consider "paper facilities," such as contracts and tariffs used to make power sales, to be facilities used for the generation, transmission or distribution of electric energy for resale, and power marketing activities will not, therefore, result in an entity's being deemed to be an electric utility company.

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        A registered holding company is required to limit its utility operations to a single integrated utility system and to divest any other operations not functionally related to the operation of that utility system. In addition, a registered holding company will require Securities and Exchange Commission approval for the issuance of securities, other major financial or business transactions, such as mergers, and transactions between and among the holding company and holding company subsidiaries.

        Because it owns Southern California Edison Company, an electric utility company, Edison International, our indirect parent company, is a holding company. Edison International is, however, exempt from registration pursuant to Section 3(a)(1) of the Public Utility Holding Company Act because the public utility operations of the holding company system are predominantly intrastate in character. Consequently, we are not a subsidiary of a registered holding company so long as Edison International continues to be exempt from registration pursuant to Section 3(a)(1) or another of the exemptions enumerated in Section 3(a). Nor are we a holding company under the Public Utility Holding Company Act because our interests in power generation facilities are as an exempt wholesale generator. Loss of exempt wholesale generator status could result in our becoming a holding company subject to registration and regulation under the Public Utility Holding Company Act and could trigger defaults under the covenants in our agreements. Becoming a holding company could, on a retroactive basis, lead to, among other things, fines and penalties and could cause certain agreements and other contracts to be voidable.

        However, under the Energy Policy Act, a company engaged exclusively in the business of owning and/or operating a facility used for the generation of electric energy exclusively for sale at wholesale may be exempted from regulation under the Public Utility Holding Company Act as an exempt wholesale generator. On March 12, 1999, the General Counsel of the Federal Energy Regulatory Commission issued a letter determining that, based on the facts stated in our application, we are an exempt wholesale generator.

        If there occurs a "material change" in facts that might affect our continued eligibility for exempt wholesale generator status, within 60 days of this material change we must:

•

file a written explanation of why the material change does not affect its exempt wholesale generator status,



•

file a new application for exempt wholesale generator status, or



•

notify the Federal Energy Regulatory Commission that it no longer wishes to maintain exempt wholesale generator status.

        If we were to lose our exempt wholesale generator status, we and our affiliates could be subject to regulation under the Public Utility Holding Company Act, that would be difficult to comply with, absent a restructuring.

Transmission of Wholesale Power

        Generally, projects that sell power to wholesale purchasers other than the local utility to which the project is interconnected require the transmission of electricity over power lines owned by others, also known as wheeling. The prices and other terms and conditions of transmission contracts are regulated by the Federal Energy Regulatory Commission when the entity providing the wheeling service is a jurisdictional public utility under the Federal Power Act. Until 1992, the Federal Energy Regulatory Commission's ability to compel wheeling was very limited, and the availability of voluntary wheeling service could be a significant factor in determining whether a site was viable for project development.

        The Federal Energy Regulatory Commission's authority under the Federal Power Act to require electric utilities to provide transmission service on a case-by-case basis to qualifying facilities, exempt wholesale generators, and other power generators was expanded substantially by the Energy Policy Act.

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Furthermore, in 1996 the Federal Energy Regulatory Commission issued a rulemaking order, Order 888, in which the Federal Energy Regulatory Commission asserted the power, under its authority to eliminate undue discrimination in transmission, to compel all jurisdictional public utilities under the Federal Power Act to file open access transmission tariffs consistent with a pro forma tariff drafted by the Federal Energy Regulatory Commission. The Federal Energy Regulatory Commission subsequently issued Orders 888-A, 888-B and 888-C to clarify the terms that jurisdictional transmitting utilities are required to include in their open access transmission tariffs. The Federal Energy Regulatory Commission also issued Order 889, which required those transmitting utilities to abide by specified standards of conduct when using their own transmission systems to make wholesale sales of power, and to post specified transmission information, including information about transmission requests and availability, on a publicly available computer bulletin board.

        In issuing Order No. 888 et al., the Federal Energy Regulatory Commission determined that the open-access rules set forth in the Order would apply to transmission with respect to wholesale sales and also with respect to retail transactions where the transmission component had been unbundled from the retail sale by state regulatory action or voluntarily by the utility making the retail sale. The Commission declined to assert jurisdiction over retail transmission that remained bundled into the retail sale. Subsequent court appeals of Order No. 888 have been brought by parties challenging the Order on the basis that the Commission had no authority to regulate the transmission of unbundled retail sales and by those challenging the Commission's failure to include the transmission of bundled retail sales in the order. On June 30, 2000, the U.S. Court of Appeals for the District of Columbia Circuit upheld the decision by the Federal Energy Regulatory Commission in both respects, finding that the Commission did have jurisdiction to regulate transmission of unbundled retail transactions, and that it was not required to assert jurisdiction over transmission embedded in bundled retail sales. In an opinion issued on March 4, 2002, the Supreme Court affirmed.

        In the meantime, while Order No. 888 was pending judicial review, it became apparent to the Federal Energy Regulatory Commission that the Order was not having the desired effects of eliminating discriminatory behavior by transmission owning utilities and in promoting the development of competitive wholesale electricity markets. Accordingly, in an effort to remedy the shortcomings it perceived, the Commission on December 20, 1999, issued Order No. 2000, which required all transmission-owning utilities to file by December 15, 2000, a statement of their plans with respect to placing their transmission assets under a RTO meeting certain criteria set forth in the Order. Although Order No. 2000 did not mandate that a utility join an RTO, it set forth various incentives for voluntary action by utilities to take such action and required them to explain in detail their reasons for deviating from the objectives set forth in the Order. RTOs meeting the Commission's criteria in Order No. 2000 were required to be operationally independent of the transmission-owning utilities whose assets they controlled and to possess other essential attributes, such as regional scope and configuration, the authority to receive and rule upon requests for service, a separate tariff governing all transactions of the RTO, a market monitoring capability, and other features. In subsequent orders, the Commission has progressively tightened its policies in favor of RTO formation, by such means as an explicit proposal that approvals of market-based rate authority for affiliates of utilities owning transmission should be tied to such utilities' placing their transmission assets in an RTO meeting the criteria of Order No. 2000. These and other regulatory initiatives by the Federal Energy Regulatory Commission are continuing to unfold at the present time, and it is not possible to predict how far or how fast they will go. However, the direction of regulatory policy at such Commission at the present time appears generally positive for continued progress toward competitive wholesale electricity markets.

Retail Competition

        In response to pressure from retail electric customers, particularly large industrial users, the state commissions or state legislatures of most states are considering, or have considered, whether to open

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the retail electric power market to competition. Retail competition is possible when a customer's local utility agrees, or is required, to unbundle its distribution service, for example, the delivery of electric power through its local distribution lines, from its transmission and generation service, for example, the provision of electric power from the utility's generating facilities or wholesale power purchases. Several state commissions and legislatures have issued orders or passed legislation requiring utilities to offer unbundled retail distribution service, which is called retail wheeling, and phasing in retail wheeling over the next several years.

        The competitive pricing environment that will result from retail competition may cause utilities to experience revenue shortfalls and deteriorating creditworthiness. However, we expect that most, if not all, state plans will insure that utilities receive sufficient revenues, through a distribution surcharge if necessary, to pay their obligations under existing long-term power purchase contracts with qualifying facilities and exempt wholesale generators. On the other hand, qualifying facilities and exempt wholesale generators may be subject to pressure to lower their contract prices in an effort to reduce the stranded investment costs of their utility customers.

Environmental Matters

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

        Typically, environmental laws require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction and operation of a project. Meeting all the necessary requirements can delay or sometimes prevent the completion of a proposed project as well as require extensive modifications to existing projects, which may involve significant capital expenditures. As a result of the sale-leaseback, a number of permits we hold have been transferred or will be transferred to the owner lessors. In addition, some permits are now held or will be held jointly with the owner lessors. We have no reason to believe that the transfer will negatively affect our business or results of operations.

        For more information on environmental regulation, see "Management's Discussion and Analysis of Results of Operations and Financial Condition—Environmental Matters and Regulations."

Employees

        At December 31, 2001, we employed 257 employees, approximately 191 of whom are covered by a collective bargaining agreement. Our skilled and disciplined workforce is well prepared to operate within a competitive and deregulated environment. We believe that our staffing levels are comparable with benchmark standards for facilities of a similar size and type. The majority of the technical staff at our facilities was retained after completing the acquisition, thus providing us with a knowledgeable and experienced base of employees.

        Our workforce is employed under a collective bargaining agreement that was restructured in 1994. The collective bargaining agreement provides us with a measure of labor cost certainty through mid 2003. The collective bargaining agreement enables us to manage our workforce and to establish flexible work rules going forward. We plan to cross train employees to perform different functions, thus minimizing the use of more expensive or less efficient subcontractors.

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ITEM 2. PROPERTIES

        We own a fee interest in the 2,413-acre site on which our generating units, Two Lick Dam and the other facilities are located. The site is approximately 45 miles northeast of Pittsburgh, Pennsylvania in Indiana County. As a result of the sale-leaseback transaction on December 7, 2001, we leased the property on which the generating units are located to the owner lessors through site leases and each owner lessor in turn subleased its undivided ground interest in the property back to us through site subleases. The term of the site leases is 45 years from the date of the sale-leaseback, with specified renewal options. The term of the site subleases is 33.67 years, the term of the sale-leaseback financing, and is renewable upon renewal of our facility leases. As long as the facility leases and the site subleases are in effect, the rents payable under the site leases and under the site subleases will be automatically offset against each other so that no amounts will be payable by us or the owner lessors with respect to these agreements. We also lease portions of the site to other third parties. Those leases are described below.

        We lease the surface of an approximately 14-acre parcel to Tanoma Coal Sales upon which the coal blending facility is located. In lieu of rental payments, Tanoma blends the first 30,000 tons of coal per month in the coal blending facility at no charge. We also lease an office building located on the site to Tanoma, which Tanoma uses for administrative activities associated with the coal blending facility. Each of the Tanoma leases expires on December 31, 2002.

        We have granted Mountain V Oil & Gas Inc. the right to operate and produce gas from existing wells located on the site, provided that gas is found in paying quantities. We receive 16% of the market value of the gas at the wellhead as royalties and also receive gas of 250,000 cubic feet at no charge from each well per annum. Mountain V currently purchases such gas from us at the market value at the wellhead.

ITEM 3. LEGAL PROCEEDINGS

        No material legal proceedings are presently pending against us.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

        Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

        All the partners' equity is, as of the date hereof, owned by Mission Energy Westside Inc. and Chestnut Ridge Energy Co. There is no market for our partnership interests.

        Dividends will be paid when declared by our general partner. We paid cash dividends to our partners totaling $138 million in 2001 and none in 2000.

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ITEM 6. SELECTED FINANCIAL DATA

        The following table includes a summary of our financial data for the years ended December 31, 2001, 2000 and 1999, respectively. We were formed on October 31, 1998 and had no significant activity during 1998. On March 18, 1999, we acquired the facilities for a purchase price of approximately $1.8 billion. Accordingly, the 1999 summary financial data relates to the activities from March 18, 1999 through December 31, 1999. The summary financial data were derived from our audited financial statements and are qualified in their entirety by the more detailed information and financial statements, including notes to these financial statements, included or incorporated by reference in this annual report.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

        The following discussion contains forward-looking statements that reflect EME Homer City Generation L.P.'s current expectations and projections about future events based on our knowledge of present facts and circumstances and our assumptions about future events. In this annual 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. 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.

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 (the "Homer City facilities") located near Pittsburgh, Pennsylvania for the purpose of producing electric energy. Although we were formed on October 31, 1998, we had no significant activity prior to the acquisition of the Homer City facilities.

        On March 18, 1999, we completed the acquisition of 100% of the ownership interests in the Homer City facilities from GPU Inc. and New York State Electric & Gas Corporation, and assumed certain liabilities of the former owners. The acquisition was financed through capital contributions by Chestnut Ridge Energy and Mission Energy Westside of approximately $273 million, and a loan of approximately $1.7 billion from Edison Mission Finance Co., a wholly-owned subsidiary of Edison Mission Holdings. The acquisition has been accounted for utilizing the purchase method. The purchase price was allocated to the assets acquired and liabilities assumed based upon their respective fair market values.

        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. See "Notes to Financial Statements—Note 3, Sale-Leaseback Transaction." 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 the 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.

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Results of Operations

        As indicated above, we acquired the Homer City facilities on March 18, 1999 and, accordingly, the 1999 results of operations includes only nine-and-a-half months of activity.

Operating Revenues

        Operating revenues increased $72.6 million in 2001 compared to 2000, and increased $95.6 million in 2000 compared to 1999. The 2001 increase was attributable to increased production and higher energy prices. The 2000 increase resulted primarily from having a full year of operation at the facilities compared to only nine-and-a-half months of activity in 1999. Energy and capacity sales were made through contracts with our marketing affiliate.

        We generated 12,922, 11,796 and 9,823 GWhr of electricity during 2001, 2000 and 1999, respectively, and had an availability factor of 87.4%, 80.2% and 86.8% during these periods. The availability factor is determined by the number of megawatt hours we are available to generate electricity divided by the number of 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 4.5%, 6.1% and 6.3% during 2001, 2000 and 1999, respectively. The availability factor increased in 2001 from 2000 due to lower forced outages and planned maintenance. The availability factor decreased in 2000 from 1999 primarily due to higher planned outages that were needed to complete our environmental improvements.

        The weighted average price for energy was $33.07/MWh, $31.63/MWh and $29.82/MWh during 2001, 2000 and 1999, respectively. The 2001 and 2000 increases were due to higher PJM market prices and higher prices obtained through forward energy contracts. See "—Market Risk Exposures—Commodity Price Risk" for further discussion of PJM market prices.

        Due to higher electric demand resulting from warmer weather during the summer months, electric revenues generated from the Homer City facilities are substantially higher during the third quarter.

        Loss from price risk management activities decreased $0.1 million in 2001 compared to 2000, and increased $0.5 million in 2000 compared to 1999. As a result of the implementation of SFAS No. 133, a small portion of our forward power purchase and sales contracts were recorded as derivatives at fair value. The changes in fair value are recognized as income (loss) from price risk management.

Operating Expenses

        Operating expenses increased $15.9 million in 2001 compared to 2000, and increased $69.9 million in 2000 compared to 1999. 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 costs increased $4.7 million in 2001 compared to 2000, and increased $39.3 million in 2000 compared to 1999. The 2001 increase is due to increased production offset by lower average fuel prices. The 2000 increase resulted primarily from having only nine-and-a-half months of activity in 1999. The average price of delivered coal per ton was $27.02, $28.95 and $31.12 during 2001, 2000 and 1999, respectively. The decrease in the average price of delivered coal per ton is due to the changes in the type of coal being used in operations. The Homer City facilities benefit from access by truck to significant native coal reserves located within the western Pennsylvania portion of the North Appalachian region. Up to 95% of the coal used by Units 1 and 2 at the facilities is supplied under existing contracts with regional mines that are located within 100 miles of the facilities, while the remainder is purchased on the spot market. The coal for the units that is purchased from local mines is cleaned by the coal-cleaning facility to reduce sulfur and ash content.

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        Plant operations costs increased $3.0 million in 2001 compared to 2000, and increased $24.3 million in 2000 compared to 1999. Plant operations costs include labor and overhead, contract services, parts and supplies and other administrative costs. The 2001 increase is primarily due to increased property insurance costs from higher premiums. The 2000 increase resulted from having only nine-and-a-half months of activity in 1999, and higher maintenance expenses during planned outages. 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 generally planned for three-year and six-year cycles. Our major maintenance expenditures are expected to be similar during the next several years.

        Depreciation and amortization increased $4.5 million in 2001 compared to 2000, and increased $10.1 million in 2000 compared to 1999. 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, future depreciation and amortization of our leasehold interest and emission credits will be based on the minimum term of the leases, which is 33.67 years.

        Administrative and general expenses were $1.8 million, $(1.9) million and $1.9 million during 2001, 2000 and 1999, respectively. Administrative and general expenses primarily include the accrual for Pennsylvania state capital tax and reflect a reduction in our accrual in 2000.

Other Income (Expense)

        Interest expense was $139.0 million, $138.7 million and $103.8 million during 2001, 2000 and 1999, respectively. Interest expense has historically been due to the indebtedness incurred to acquire the Homer City facilities. As a result of the sale-leaseback, future interest expense will primarily be from the lease financing, plus outstanding borrowings on our subordinated revolving loan agreement with Edison Mission Finance.

        Interest and other income was $0.4 million, $3.0 million and $1.0 million during 2001, 2000 and 1999, respectively. Interest and other income primarily relates to interest earned on cash and cash equivalents.

Provision (Benefit) for Income Taxes

        We had effective tax provision (benefit) rates before extraordinary item of 43.6%, (11.0%) and 52.2% in 2001, 2000 and 1999, respectively. During 2000 and 1999, our partners were responsible for Pennsylvania state income taxes. Effective January 1, 2001, our status in Pennsylvania changed to a corporation due to changes in Pennsylvania tax regulations, which means that we are now subject to Pennsylvania state income taxes. As a result, we provided for $6 million in Pennsylvania state income taxes during 2001. Our effective tax provision (benefit) rate varies from the federal statutory rate of 35% due to state income taxes.

Extraordinary Gain (Loss)

        As a result of the sale-leaseback transaction on December 7, 2001, we recorded an extraordinary gain in 2001 of $5.7 million, net of income tax of $4.4 million, attributable to the extinguishment of debt that was assumed in the transaction. The early repayment of a $800 million term loan in May 1999 resulted in an extraordinary loss of $2.9 million in 1999, net of income tax benefit of $2.1 million, attributable to the write-off of unamortized debt issue costs.

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Related Party Transactions

        We have entered into energy and emission allowance sales agreements with a marketing affiliate for the sale of energy and capacity at a price equal to (i) the price which a third-party purchaser of the capacity or energy has agreed to pay less (ii) $.02 per MWh of capacity and energy plus an emission allowance fee. Payment is due and payable within thirty days from billing which is rendered on a monthly basis. For the years ended December 31, 2001 and 2000, the amount due from the marketing affiliate was $22.7 million and $69.7 million, respectively. The net fees earned by the marketing affiliate were $0.9 million, $1.5 million and $0.2 million for the years ended December 31, 2001, 2000 and 1999, respectively.

        During 2001, we entered into an option for installed capacity, and five transactions, including the exercise of the aforementioned option, for installed capacity with our marketing affiliate. Each transaction was at fair market value for such installed capacity at the time. Payments for the option and the five transactions amounted to approximately $29.5 million.

        We entered into several transactions in 2001 through our marketing affiliate for the purchase of SO(2) allowances from another affiliate of Edison Mission Energy. All transactions were completed at market price on the date of the transaction. Total consideration paid was $10.2 million.

        We entered into agreements with Edison Mission Energy Services, Inc., an affiliate, to provide fuel and transportation services related to coal and fuel oil. Under the terms of these agreements, we pay a service fee of $.06 for each ton of coal delivered and $.05 for each barrel of fuel oil delivered, plus the actual cost of the commodities. The amount billable under this agreement for each of the three years ended December 31, 2001, 2000 and 1999 was $0.3 million.

        We have obtained financing from an affiliate in connection with our acquisition of the Homer City facilities. For further discussion, see "Contractual Obligations, Commitments and Contingencies—Long-Term Debt to Affiliate."

        Certain administrative services such as payroll, employee benefit programs, insurance and information technology are shared among all affiliates of Edison International and the costs of these corporate support services are allocated to all affiliates. The cost of services provided by Edison International and Edison Mission Energy, including those related to us, are allocated based on one of the following formulas: percentage of the time worked, equity in investment and advances, number of employees, or multi-factor (operating revenues, operating expenses, total assets and total employees). We participate in a common payroll and benefit program with all Edison International employees. In addition, we are billed for any direct labor and out-of-pocket expenses for services directly requested for the benefit of the partnership. We believe the allocation methodologies are reasonable. We made reimbursements for the cost of these programs and other services totaling $26.8 million, $30.0 million and $18.1 million for the years ended December 31, 2001, 2000 and 1999, respectively.

        We participate in the insurance program of Edison International, including property, general liability, workers compensation and various other specialty policies. Our insurance premiums are generally based on our share of risk related to each policy. In connection with the property insurance program, a portion of the risk is reinsured by a captive insurance subsidiary of Edison International. Under these reinsurance policies, we are entitled to receive a premium refund to the extent that our loss experience is less than estimated.

        We have also recorded a receivable from Edison Mission Energy of $58.5 million and $59.4 million at December 31, 2001 and 2000, respectively, related to the tax due under the tax sharing agreement. See "—Note 2. Summary of Significant Accounting Policies—Income Taxes" for further discussion of the tax sharing agreement.

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