EME HOMER CITY GENERATION LP - 10-K Annual Report

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

EME Homer City Generation L.P.
(Exact name of registrant as specified in its charter)

Pennsylvania (State or other jurisdiction of incorporation or organization)		33-0826938 (I.R.S. Employer Identification No.)
1750 Power Plant Road Homer City, Pennsylvania (Address of principal executive offices)		15748 (Zip Code)

None		Not Applicable
(Title of Class)		(Name of each exchange on which registered)

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.

Item		Page
PART I
1.	Business	1
2.	Properties	15
3.	Legal Proceedings	15
4.	Submission of Matters to a Vote of Security Holders	15
PART II
5.	Market for Registrant's Common Equity and Related Stockholder Matters	15
6.	Selected Financial Data	16
7.	Management's Discussion and Analysis of Results of Operations and Financial Condition	17
7a.	Quantitative and Qualitative Disclosures About Market Risk	35
8.	Financial Statements and Supplementary Data	35
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	35
PART III
10.	Directors and Executive Officers of the Registrant	63
11.	Executive Compensation	64
12.	Security Ownership of Certain Beneficial Owners and Management	64
13.	Certain Relationships and Related Transactions	64
PART IV
14.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	65
	Signatures	71

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.

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:

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.

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.

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

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.

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

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.

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.

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.

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.

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.

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.

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.

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 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.

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.

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.

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

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.

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

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.

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.

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 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

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.

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

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.

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:

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.

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.

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.

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

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.

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."

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.

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 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.

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.

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.

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.

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 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 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.

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.

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.

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.

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.

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.

Historically, we have not been charged for an allocation of the Chicago Office of Edison Mission Energy's Americas Region since our inception in late 1999 due to our principal focus on power plants in Illinois. The Chicago Office has technical and managerial responsibility for our operations. However, we may be charged in the future for a share of these costs. If these costs were allocated to us, they would be recorded as a non-cash charge against our operations as an in-kind contribution of services through our parent. Accordingly, there would be no cash impact of an allocation of such costs on our operations. We do not believe that we would incur a material amount of additional costs to operate our Homer City plant on the basis of an unaffiliated relationship with Edison Mission Energy.

At December 31, 2001, we had cash and cash equivalents of $38.5 million compared to $19.1 million at December 31, 2000. Net working capital at December 31, 2001 was $87.7 million compared to $107.6 million at December 31, 2000.

Net cash provided by operating activities decreased $34.2 million in 2001 compared to 2000 and decreased $67.6 million in 2000 compared to 1999. The 2001 change is primarily due to the recognition of a taxable gain, payment of a swap deposit with a bank and payment of affiliate interest, offset by the timing of working capital requirements. The 2000 change is due to the timing of working capital requirements.

Net cash used in financing activities totaled $531.7 million in 2001, compared to net cash provided by financing activities of $99.2 million and $1.9 billion in 2000 and 1999, respectively. In 2001, the sale-leaseback transaction enabled us to pay down long-term debt and pay dividends to our partners. In 2000, net cash provided by financing activities was primarily due to borrowings of long-term debt. In 1999, net cash provided by financing activities was primarily due to borrowings entered into in order to acquire the Homer City facilities.

Net cash provided by investing activities totaled $568.3 million in 2001, compared to net cash used in investing activities of $141.6 million and $1.9 billion in 2000 and 1999, respectively. In 2001, net cash provided by investing activities was due to proceeds received from the sale-leaseback transaction, partially offset by a deposit to a restricted cash account to support the lease, and capital expenditures. In 2000, net cash used in investing activities was due to capital expenditures. In 1999, net cash used in investing activities was due to the purchase of the Homer City facilities and capital expenditures.

Capital expenditures were $83.2 million, $141.6 million and $105.0 million for the years ended December 31, 2001, 2000 and 1999, 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 will produce environmental improvements and 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. The installation of these improvements is scheduled to be completed in 2002. See "Recent Developments" for discussion of an outage related to a collapse of ductwork on Unit No. 3. We expect to spend approximately $27 million in 2002 on capital expenditures to the Homer City facilities, including environmental expenditures disclosed under "—Environmental Matters and Regulations."

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, although they are under no legal obligation to do so.

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. 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.

The following table summarizes the majority of our contractual obligations and commercial commitments as of December 31, 2001.

As part of the purchase of the Homer City facilities, we obtained loans from Edison Mission Finance. A portion of the borrowings outstanding was repaid with the proceeds from the sale-leaseback. Under the terms of our loan with Edison Mission Finance, the principal amount is due in 2014, with no scheduled repayment prior to its maturity. This loan is subordinated to our lease rent obligations with interest and principal payments subject to limitations based on our ability to make distributions under the lease.

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 assumption of debt (the fair value of which was $809.3 million). Under the terms of the 33.67-year leases, we are obligated to make semi-annual lease payments on each April 1 and October 1. The gain recognized on the sale of the facilities has been deferred and is being amortized over the term of the leases.

We have entered into several fuel purchase agreements with various third-party suppliers for the purchase of bituminous steam coal and fuel oil. These contracts call for the purchase of a minimum quantity over the term of the contracts, which extend from one to six years from December 31, 2001, with an option at our discretion to purchase additional amounts as stated in the agreements.

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 include 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 "—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.

In connection with the sale-leaseback transaction, we have entered into a swap agreement with a bank in order to more effectively match our cash flow, which is higher during the summer months when energy prices are higher. Under the terms of this swap, we 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 us in April of each year and we will make a swap payment to the bank in October of each year. The amount of payments are designed to reverse the semi-annual payments due under the lease such that we effectively have lower cash obligations in April and higher cash obligations in October. The implicit interest rate included in the swap is LIBOR during periods that we have a net deposit with the bank, and LIBOR plus 5% during periods that we have a net loan with the bank.

Our primary market risk exposures arise from changes in electricity and fuel prices. We manage these risks in part by using derivative financial instruments in accordance with established policies and procedures.

Our revenues and results of operations are dependent upon prevailing market prices for energy, capacity 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 past three years:

	24-Hour PJM Prices*
	2001		2000		1999
January	$	36.66	$	23.15	$	19.92
February		29.53		23.84		16.51
March		35.05		21.97		19.60
April		34.58		23.79		21.43
May		28.64		28.41		22.55
June		26.61		23.06		36.93
July		30.21		23.53		90.10
August		43.99		29.01		28.87
September		22.44		25.12		21.54
October		21.95		29.20		19.80
November		19.58		30.68		16.48
December		19.66		44.63		18.07

Yearly Average	$	29.07	$	27.20	$	27.65

As shown on the above table, the average market prices during the last three months of 2001 are below the average market prices during the last three months of 2000. In addition, the forecasted calendar year market prices in PJM beginning January 2, 2002 through March 12, 2002 range from approximately $23 to $28. Among the factors that may influence future market prices for energy, capacity and ancillary services in PJM and NYISO are:

Our ability to make payments of lease rent on the facility leases is dependent 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 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 used for price risk management activities by instrument type:

		December 31,
		2001		2000
Commodity price:
	Forwards	$	35,881	$	(117,803	)
	Options		—		1,811
	Swaps		—		(892	)

The fair value of forward commodity contracts at December 31, 2001 was an asset compared to a liability at December 31, 2000. The substantial change in fair value of the outstanding contracts at the end of each of these periods is primarily due to the following:

A 10% increase in electricity forward prices would result in a $12.9 million decrease in the fair market value of energy contracts at December 31, 2001 entered into by our marketing affiliate. A 10% decrease in electricity forward prices would result in a $12.9 million increase in the fair market value of energy contracts at December 31, 2001 entered into by our marketing affiliate.

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.

Our ability to make payments of lease rent under the facility leases is dependent on the market conditions for the sale of capacity and energy.

General operating risks may decrease or eliminate the revenues generated by the facilities or increase their operating costs.

The operation of power generation facilities involves many operating risks, including:

Although we employ experienced operating personnel to operate the facilities and will maintain insurance, including business interruption insurance, to mitigate the effects of the operating risks described above, we cannot assure you that the occurrence of one or more of the events listed above would not significantly decrease or eliminate revenues generated by the facilities or significantly increase the costs of operating them. A decrease or elimination in revenues generated by the facilities or an increase in the costs of operating them could decrease or eliminate funds available to make lease rent payments.

The revenues generated by the operation of the facilities are subject to market demand for energy, capacity and ancillary services, which is beyond our control.

We derive revenue from the sale of energy and capacity into the Pennsylvania-New Jersey-Maryland power market, which we refer to as PJM, and the New York Independent System Operator, which we refer to as NYISO, and from bilateral contracts with power marketers and load serving entities within PJM, NYISO and the surrounding markets. Participants in PJM and NYISO are not guaranteed any specified rate of return on their capital investments through recovery of mandated rates payable by purchasers of electricity. Therefore, with the exception of nominal revenue, our revenues and results of operations are dependent upon prevailing market prices for energy, capacity and ancillary services in the PJM, NYISO and other competitive markets.

Among the factors that influence the market prices for energy, capacity and ancillary services in PJM and NYISO are:

Our business is subject to substantial regulations and permitting requirements, and our revenues may decrease or our operating costs may increase because of our inability to comply with existing regulations or requirements or changes in applicable regulations or requirements.

Our business is subject to extensive energy and environmental regulation by federal, state and local authorities. We are required to comply with numerous laws and regulations and to obtain numerous governmental permits in the operation or ownership of the facilities, as the case may be. We cannot assure you that existing regulations will not be revised or reinterpreted, that new laws and regulations will not be adopted or become applicable to us or the facilities or that future changes in laws and regulations will not have a detrimental effect on our business.

We believe that we have obtained all material energy-related federal, state and local approvals currently required to operate the facilities. Although not currently required, additional regulatory approvals may be required in the future due to a change in laws and regulations, a change in our customers or for other reasons. We cannot assure you that we will be able to obtain all required regulatory approvals that we do not yet have or that we may require in the future, or that we will be able to obtain any necessary modifications to existing regulatory approvals or maintain all required regulatory approvals. If there is a delay in obtaining any required regulatory approvals or if we fail to obtain and comply with any required regulatory approvals, the operation of the facilities or the sale of electricity to third parties could be prevented or subject to additional costs.

We are required to comply with numerous statutes, regulations and ordinances relating to the safety and health of employees and the public, the protection of the environment and land use. We believe that we have obtained all material environmental and land use permits and approvals currently required to operate the facilities. The environmental, land use and health and safety statutes, regulations and ordinances are constantly changing. We may incur significant additional costs to comply with new requirements. If we fail to comply with existing or new requirements, we could be subject to civil or criminal liability and the imposition of clean-up liens or penalties. In acquiring the facilities, we assumed, subject to some limited exceptions, all on-site liabilities associated with the environmental condition of the facilities, regardless of when the liabilities arose and whether known or unknown, and generally agreed to indemnify the former owners of the facilities for these liabilities. We cannot assure you that we will at all times be in compliance with all applicable environmental laws and regulations or that steps to bring the facilities into compliance would not materially and adversely affect our ability to make payments of lease rent under the facility leases.

One of our strategies for compliance with federal regulations regarding emissions of sulfur dioxide and federal and state regulations regarding emissions of nitrogen oxide is the construction of the environmental capital improvements to the units. A delay in the completion of these improvements or the failure of the improvements to perform to their technical specifications could adversely affect our compliance strategy and require us to purchase emissions allowances or reduce the expected levels of operation of the units. Although our contract for the construction of these environmental capital improvements contains customary performance and completion guarantees, we cannot assure you that the improvements will be completed when anticipated or whether those systems will perform at the expected levels.

Restrictions in the participation agreements and facility leases will limit or prohibit us from entering into some transactions that we otherwise might enter into.

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 funding, which they are under no legal obligation to do so.

In connection with the sale-leaseback transaction, we entered into a designated account representative agreement with the owner lessors which provides that, for as long as the facility leases are in effect, we will be irrevocably appointed as the designated account representatives on file with the Environmental Protection Agency or the Department of Environmental Protection, as the case may be, entitled to buy, sell and otherwise dispose of emission allowances without any payments or consideration to the owner lessors. The agreement provides that upon termination of a facility lease, the applicable owner lessor will have the right to appoint itself or any other person as our successor designated account representative for purposes of any future emission allowances not then owned by us. If a facility lease were to terminate before its expiration, this event would also terminate the account representative agreement, and we would be required to write-off any unamortized emission allowances that we would no longer control.

We are required to have insurance for the facilities, including all-risk property damage insurance, commercial general public liability insurance, boiler and machinery coverage and business interruption insurance. We cannot assure you that the insurance coverage for the facilities will be available in the future on commercially reasonable terms. We also cannot assure you that the insurance proceeds received for any loss of the facilities or any damage to the facilities will be sufficient to permit us to make any payments of rent under the facility leases.

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 initiated 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.

Water Quality. Our coal-cleaning plant National Pollutant Discharge Elimination System (NPDES) permit issued in 1995 has been administratively extended in accordance with 25 PA Code

Section 92.9(b) until a new permit is issued by the Pennsylvania Department of Environmental Protection (PADEP) Bureau of Water Management. Modeling results indicate that PADEP may impose more stringent discharge limits for some contaminants at the time of renewal of these permits, which may require upgrade of our facilities' wastewater treatment systems with such approaches as reverse osmosis, ozonation, dechlorination and/or recycling of water.

We conduct ground water monitoring in a number of areas throughout the site, including active and former ash disposal sites, wastewater and runoff settling and drainage ponds and a coal refuse disposal site. On September 27, 2001, the PADEP responded to an Assessment Report by stating that no further groundwater assessment or abatement is required for the industrial waste treatment ponds. To date, PADEP has not requested that any additional remediation actions be performed at the site. Our facilities have a drinking water treatment system designed to meet applicable potable water standards. Recent tests indicate that our facilities' drinking water supply meets these standards.

Helvetia Discharges. Our 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. Should Helvetia default on its treatment obligations, the government may attempt to require us to fund these commitments.

Penn Hill No. 2 and Dixon Run No. 3 Discharges. In connection with our purchase of the Homer City facilities, we 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 us that we were potentially liable for treating the two discharges solely because of our ownership of the property from which the discharges emanated. Without any admission of our liability, we 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 we are 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 us that they plan no further action.

A draft consent decree agreement that addresses remedial responsibilities for the two discharges has been prepared by PADEP. Under its terms, we are responsible for designing and implementing a permanent system to collect and treat the Dixon Run No. 3 discharge. We will continue our funding of the existing collection and treatment system until the Dixon Run No. 3 treatment system becomes

operational. The state has 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 $15,000 per month. We expect 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. We are evaluating options for permanent treatment of the Dixon Run No. 3 discharge, including a passive system involving wetlands treatment. The total cost of a passive treatment system is estimated to be $1 million, but its operational costs are considerably less than those of a conventional chemical treatment system.

Clean Air Act. We expect that compliance with the Clean Air Act and the regulations and revised State Implementation Plans developed as a consequence of the Act will result in increased capital expenditures and operating expenses. For example, we expect to spend approximately $17.8 million in 2002 to complete installation of the upgrades to the environmental controls at our facilities to reduce sulfur dioxide and nitrogen oxide emissions.

Mercury MACT Determination. On December 20, 2000, the Environmental Protection Agency issued a regulatory finding that it is "necessary and appropriate" to regulate emissions of mercury and other hazardous air pollutants from coal-fired power plants. The agency has added coal-fired power plants to the list of source categories under Section 112(c) of the Clean Air Act for which "maximum available control technology" standards will be developed. Eventually, unless overturned or reconsidered, the Environmental Protection Agency will issue technology-based standards that will apply to every coal-fired unit owned by us or our affiliates in the United States. This section of the Clean Air Act provides only for technology-based standards, and does not permit market trading options. Until the standards are actually promulgated, the potential cost of these control technologies cannot be estimated, and we cannot evaluate the potential impact on the operations of our facilities.

National Ambient Air Quality Standards. A new ambient air quality standard was adopted by the Environmental Protection Agency in July 1997 to address emissions of fine particulate matter. It is widely understood that attainment of the fine particulate matter standard may require reductions in nitrogen oxides and sulfur dioxides, although, under the time schedule announced by the Environmental Protection Agency when the new standard was adopted, non-attainment areas were not to have been designated until 2002 and control measures to meet the standard were not to have been identified until 2005. In May 1999, the United States Court of Appeals for the District of Columbia Circuit held that Section 109(b)(1) of the Clean Air Act, the section of the Clean Air Act requiring the promulgation of national ambient air quality standards, as interpreted by the Environmental Protection Agency, was an unconstitutional delegation of legislative power. The Court of Appeals remanded both the fine particulate matter standard and the revised ozone standard to allow the Environmental Protection Agency to determine whether it could articulate a constitutional application of Section 109(b)(1). On February 27, 2001, the Supreme Court, in Whitman v. American Trucking Associations, Inc., reversed the Circuit Court's judgment on this issue and remanded the case back to the Court of Appeals to dispose of any other preserved challenges to the particulate matter and ozone standards. Accordingly, as the final application of the revised particulate matter ambient air quality standard is potentially subject to further judicial proceedings, the impact of this standard on our facilities is uncertain at this time.

We believe that our facilities are in material compliance with applicable state and federal air quality requirements. Further reductions in emissions may be required for the achievement and maintenance of National Ambient Air Quality Standards for ozone and fine particulate matter and with respect to the implementation of regulations designed to reduce regional haze.

Clean Water Act—§ 316(b) Rulemakings. The Environmental Protection Agency proposed rules establishing standards for the location, design, construction and capacity of cooling water intake structures at new facilities, including steam electric power plants. Under the terms of a consent decree entered into by the U.S. District Court for the Southern District of New York in Riverkeeper, Inc. v. Whitman, regulations for new facilities were adopted by November 9, 2001. Pursuant to the consent decree, the agency proposed similar regulations for existing facilities on February 28, 2002, and is required to finalize those regulations by August 28, 2003. Until the final standards are promulgated, we cannot determine their impact on our facilities or estimate the potential cost of compliance.

Comprehensive Environmental Response, Compensation, and Liability Act. Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products located at that facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by these parties in connection with these releases or threatened releases. Many of these laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA), as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under these laws to be strict and joint and several. The cost of investigation, remediation or removal of these substances may be substantial. In connection with the ownership and operation of our facilities, we may be liable for these costs.

In addition, persons who arrange for the disposal or treatment of hazardous or toxic substances at a disposal or treatment facility may be liable for the costs of removal or remediation of a release or threatened release of hazardous or toxic substances at that disposal or treatment facility, whether or not that facility is owned or operated by that person. Some environmental laws and regulations create a lien on a contaminated site in favor of the government for damages and costs it incurs in connection with the contamination. The owner of a contaminated site and persons who arrange for the disposal of hazardous substances at that site also may be subject to common law claims by third parties based on damages and costs resulting from environmental contamination emanating from that site. In connection with the ownership and operation of our facilities, we may be liable for these costs.

Several federal, state and local laws, regulations and ordinances also govern the removal, encapsulation or disturbance of asbestos-containing materials when these materials are in poor condition or in the event of construction, remodeling, renovation or demolition of a building. Those laws and regulations may impose liability for release of asbestos-containing materials and may provide for the ability of third parties to seek recovery from owners or operators of these properties for personal injury associated with asbestos-containing materials. In connection with the ownership and operation of our facilities, we may be liable for these costs.

Enforcement Issues. On November 3, 1999, the United States Department of Justice filed suit against a number of electric utilities for alleged violations of the Clean Air Act's New Source Review, or NSR, requirements related to modifications of air emissions sources at electric generating stations located in the southern and midwestern regions of the United States. Several states have joined these lawsuits. In addition, the United States Environmental Protection Agency has also issued administrative notices of violation alleging similar violations at additional power plants owned by some of the same utilities named as defendants in the Department of Justice lawsuit, as well as other utilities, and also issued an administrative order to the Tennessee Valley Authority for similar violations at certain of its power plants. The Environmental Protection Agency has also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities, including the prior owners of the Homer City plant, seeking to determine whether these utilities also engaged in activities that may have been in violation of the Clean Air Act's NSR requirements.

To date, one utility, the Tampa Electric Company, has reached a formal agreement with the United States to resolve alleged new source review violations. Two other utilities, the Virginia Electric & Power Company and Cinergy Corp., have reached agreements in principle with the Environmental Protection Agency, although these agreements may be revisited to be consistent with anticipated NSR policy changes. In each case, the settling party has agreed to incur over $1 billion in expenditures over several years for the installation of additional pollution controls, the retirement or repowering of coal-fired generating units, supplemental environmental projects and civil penalties. These agreements provide for a phased approach to achieving required emission reductions over the next 10 to 15 years. The settling utilities have also agreed to pay civil penalties ranging from $3.5 million to $8.5 million.

In May 2001, President Bush issued a directive for a 90-day review of NSR "interpretation and implementation" by the Administrator of the Environmental Protection Agency and the Secretary of the U.S. Department of Energy. The results of the review have been postponed with release likely sometime during the first half of 2002. President Bush also directed the Attorney General to review ongoing NSR legal actions to "ensure" they are "consistent with the Clean Air Act and its regulations." The Department of Justice review was released in January 2002 and concluded "EPA has a reasonable basis for arguing that the enforcement actions are consistent with both the Clean Air Act and the Administrative Procedure Act." Both actions were recommendations detailed within the Bush administration's "National Energy Policy Task Force Report."

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

United Nations Framework Convention on Climate Change. Since the adoption of the United Nations Framework Convention on Climate Change in 1992, there has been worldwide attention with respect to greenhouse gas emissions. In December 1997, the Clinton administration participated in the Kyoto, Japan negotiations, where the basis of a Climate Change treaty was formulated. Under the treaty, known as the Kyoto Protocol, the United States would be required, by 2008-2012, to reduce its greenhouse gas emissions by 7% from 1990 levels.

The Kyoto Protocol has yet to be submitted to the U.S. Senate for ratification. In March 2001, the Bush administration announced that the United States would not ratify the Kyoto Protocol, but would instead offer an alternative. Various bills have been, or are expected to be, introduced in Congress to address some of these implementing guidelines and other aspects of climate change. Apart from the Kyoto Protocol, we may be impacted by future federal or state legislation relating to controlling greenhouse gas emissions.

Notwithstanding the Bush administration position, environment ministers from around the world have reached a compromise agreement on the mechanics and rules of the Kyoto Protocol. The compromise agreement is believed to clear the way for countries to begin the treaty ratification process.

If we do become subject to limitations on emissions of carbon dioxide from our fossil fuel-fired electric generating plants, these requirements could have a significant economic impact on our operations.

The accounting policies described below are viewed by management as "critical" because their correct application requires the use of material estimates and have a material impact on our financial results and position.

We engage in price risk management activities for non-trading purposes. Derivative financial instruments are mainly utilized by us to manage exposure from changes in electricity prices. Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." This Statement establishes accounting and reporting standards requiring that derivative instruments be recorded in the balance sheet as either assets or liabilities measured at their fair value unless they meet an exception. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify for hedge accounting, depending on the nature of the hedge, changes in fair value are either offset by changes in the fair value of the hedged assets, liabilities or firm commitments through earnings, or recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value is immediately recognized in earnings.

Management's judgment is required to determine if transactions meet the definition of a derivative and if they do, whether the normal sales and purchases exception apply or whether individual transactions qualify for hedge accounting treatment. Our power sales and fuel supply agreements generally do not meet the definition of a derivative as they are not readily convertible to cash or qualify as normal purchases and sales under SFAS No. 133 and are, therefore, recorded at an accrual basis.

We follow Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This Statement establishes accounting and reporting standards for the impairment or disposal of long-lived assets. SFAS No. 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" but retains the requirements to recognize an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and to measure an impairment loss as the difference between the carrying amount and fair value of the asset less cost to sell, whether reported in continuing operations or in discontinued operations.

Factors we consider important, which could trigger an impairment, include operating losses from a project, projected future operating losses, or significant negative industry or economic trends. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. If an impairment has occurred, the amount of the impairment loss recognized would be determined by estimating the fair value of the assets and recording a loss if the fair value was less than the book value. We also record an impairment if we make a decision, which generally occurs if we reach an agreement to sell an asset, to dispose of an asset and the fair value is less than our book value.

For additional information regarding our accounting policies, see "EME Homer City Generation L.P. Notes to Financial Statements—Note 2."

In October 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The Statement establishes accounting and reporting standards for the impairment or disposal of long-lived assets. The Statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" but retains SFAS No. 121 requirements to recognize an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and to measure an impairment loss as the difference between the carrying amount and fair value of the asset less cost to sell, whether reported in continuing operations or in discontinued operations. In addition, SFAS No. 144 broadens the reporting of discontinued operations to include a component of an entity that has been disposed of or is classified as held for sale. The standard, effective on January 1, 2002, was adopted by us in the fourth quarter of 2001 and had no impact on our financial statements.

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

On February 10, 2002, the ductwork and bypass associated with the selective catalytic reduction system of one of the units, known as Unit 3, collapsed. No fire occurred and no injuries were reported as a result of the event.

We have now completed a preliminary investigation of the event and currently project that Unit 3 will return to service in mid-April 2002. We also 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. Further, for events of this kind, we maintain business interruption insurance that provides for lost revenues, net of costs, for outage periods beyond sixty days. A more in-depth analysis of the root causes of the event is required to determine the extent to which insurers and/or the contractor will cover the resulting costs of property damage and repair. This investigation continues.

The selective catalytic reduction system for Unit 3, which reduces emissions of nitrogen oxides from the boiler flue gas during the summer season, had been undergoing performance tests following its recent construction and installation. At the time of the collapse, the unit was operating with the selective catalytic reduction system bypassed. When returned to service, the unit will initially operate in this bypass mode. Reconnection of the selective catalytic reduction system will be implemented at a later date in accordance with an outage plan to be developed.

Information responding to Item 7A is filed with this report under Item 7. "Management's Discussion and Analysis of Results of Operations and Financial Condition."

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

We have audited the accompanying balance sheets of EME Homer City Generation L.P. (a Pennsylvania limited partnership) as of December 31, 2001 and 2000, and the related statements of income (loss), comprehensive income (loss), partners' equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of EME Homer City Generation L.P. as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.

EME HOMER CITY GENERATION L.P.

STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

EME HOMER CITY GENERATION L.P.

NOTES TO FINANCIAL STATEMENTS

(Dollars in thousands)

EME Homer City Generation L.P. was 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. The partnership was 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 the partnership was formed on October 31, 1998, it had no significant activity prior to the acquisition of the Homer City facilities.

On March 18, 1999, the partnership completed its 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 accompanying financial statements reflect the operations of the Homer City facilities commencing from the date of acquisition. 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, the partnership 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 "—Note 3. Sale-Leaseback Transaction." In connection with the sale-leaseback transaction, the partnership agreement was amended to change, among other things, the ownership interests in us to 99.9 percent for Chestnut Ridge Energy and 0.1 percent for Mission Energy Westside.

The Homer City facilities consist of three coal-fired steam turbine units, one coal preparation facility, an 1,800-acre dam site and associated support facilities. Units 1 and 2 are essentially identical steam turbine generators with net summer capacities of 620 MW and 614 MW, respectively. Units 1 and 2 began commercial operation in 1969. Unit 3 is also a steam turbine generator with a net summer capacity of 650 MW. Unit 3 began commercial operations in 1977.

The partnership derives 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 between its marketing affiliate and power marketers and load serving entities within PJM, NYISO and the surrounding markets. The partnership has entered into a contract with a marketing affiliate for the sale of energy and capacity produced by the Homer City facilities, which enables such marketing affiliate to engage in forward sales and hedging transactions to manage electricity price exposure. The marketing affiliate has systems in place that monitor real-time spot and forward pricing and perform options valuations. Under this contract, the partnership pays the marketing affiliate fees for these marketing services.

Certain amounts in the prior years have been reclassified to conform to the current year's presentation.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

The partnership considers cash and cash equivalents to include cash and short-term investments with original maturities of three months or less.

Inventory consists of spare parts, coal and fuel oil and is stated at the lower of weighted average cost or market.

Property, plant and equipment are stated at cost. Depreciation and amortization is computed on a straight-line basis over the following estimated useful lives:

Leasehold improvements		33.67 years
Plant and equipment under lease financing		33.67 years
Emission allowances		33.67 years
Equipment, furniture and fixtures		4 to 10 years

As part of the acquisition of the Homer City facilities, the partnership acquired emission allowances under the Environmental Protection Agency's Acid Rain Program. Although the emission allowances granted under this program are freely transferable, the partnership intends to use substantially all of the emission allowances in the normal course of its business to generate electricity. Accordingly, the partnership has classified emission allowances expected to be used to generate power as part of property, plant and equipment. Acquired emission allowances were amortized over the estimated lives of the Homer City units on a straight-line basis until completion of the sale-leaseback transaction described in Note 3. Effective December 7, 2001, the completion date of the sale-leaseback transaction, the partnership changed the period of amortization of emission allowances from 39 years to 33.67 years, the term of the leases.

The partnership periodically evaluates the potential impairment of its long-lived assets based on a review of estimated future cash flows expected to be generated. If the carrying amount of the asset exceeds the amount of the expected future cash flows, undiscounted and without interest charges, then an impairment loss for our long-lived assets is recognized in accordance with Statement of Financial Accounting Standards No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets."

Certain major pieces of the partnership's equipment require repairs and maintenance on a periodic basis. These costs, including major maintenance costs, are expensed as incurred.

	2001		2000
Deferred financing costs	$	—	$	13,672
Accumulated amortization		—		(2,381	)

Net deferred financing costs	$	—	$	11,291

Deferred financing costs consist of legal and other costs incurred by the partnership to obtain long-term financing. See "—Note 5. Long-Term Debt." These costs were amortized as interest expense over the life of the related long-term debt using the effective interest method. As a result of the assumption of the partnership's debt by the buyers in the sale-leaseback transaction on December 7, 2001, these costs were included in determining the gain on early extinguishment of debt.

Interest incurred on funds borrowed by us to finance project construction is capitalized. Capitalization of interest is discontinued when the projects are completed and deemed operational. Such capitalized interest is included in property, plant and equipment. The partnership capitalized $10.5 million, $10.3 million and $1.8 million for the years ended December 31, 2001, 2000 and 1999, respectively.

Revenues and related costs are recorded as electricity is generated or as services are provided.

Effective January 1, 2001, the partnership adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." The Statement establishes accounting and reporting standards requiring that derivative instruments be recorded in the balance sheet as either assets or liabilities measured at their fair value unless they meet an exception. The

Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. For derivatives that qualify for hedge accounting, depending on the nature of the hedge, changes in fair value are either offset by changes in the fair value of the hedged assets, liabilities or firm commitments through earnings, or recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value is immediately recognized in earnings.

Effective January 1, 2001, the partnership recorded all derivatives at fair value unless the derivatives qualified for the normal sales and purchases exception. The partnership does not believe that its physical coal contracts are readily convertible to cash as defined under SFAS No. 133 and, therefore, are not derivatives. The partnership did not use this exception for its forward sales contracts due to the net settlement procedures used by its marketing affiliate with counterparties for the period between January 1, 2001 through June 30, 2001. Forward sales contracts qualified for treatment under SFAS No. 133 as cash flow hedges with appropriate adjustments made to other comprehensive income for the period between January 1, 2001 through June 30, 2001. The cumulative effect on prior periods' net income resulting from this change in accounting for derivatives in accordance with SFAS No. 133 was not material. The partnership recorded a $69.3 million, after tax, unrealized holding loss upon adoption of this change in accounting principle reflected in partners' equity in the balance sheet.

Effective July 1, 2001, the Derivative Implementation Group of the Financial Accounting Standards Board modified the normal sales and purchases exception to include electricity contracts, which include terms that require physical delivery by the seller in quantities that are expected to be sold in the normal course of business. Accordingly, the partnership qualified to use the normal sales and purchases exception for its forward sales contracts commencing July 1, 2001. Based on this accounting guidance, on July 1, 2001, the partnership eliminated the value of its forward sale contracts from its balance sheet. The cumulative effect of this change in accounting is reflected as a $17.4 million decrease in other comprehensive income.

The partnership has entered into a contract with a marketing affiliate for the sale of energy and capacity produced by the partnership, which enables such marketing affiliate to engage in forward sales and hedging transactions to manage the partnership's electricity price exposure. Net gains or losses on hedges by the marketing affiliate that are physically settled are recognized in the same manner as the hedged item.

The partnership has made an election to be taxed as a corporation for federal and California state tax purposes and, as such, will be included in the consolidated federal income tax and combined California state franchise tax returns of Edison International. The partnership calculates its income tax provision on a separate company basis under a tax sharing arrangement with an affiliate of Edison International, which in turn has an agreement with Edison International. Tax benefits generated by the partnership for federal and California state tax purposes are recognized by the partnership without regard to separate company limitations.

The partnership accounts for income taxes using the asset-and-liabilities method, wherein deferred tax assets and liabilities are recognized for future tax consequences of temporary differences between the carrying amounts and the tax bases of assets and liabilities using enacted rates.

Effective January 1, 2001, the partnership is being treated as a corporation for Pennsylvania state income tax purposes, and accordingly has reflected the Pennsylvania state tax provision in the financial statements. Prior to 2001, the partnership was treated as a partnership for Pennsylvania state income tax purposes, and the income or loss of the partnership was included in the Pennsylvania state income tax returns of the individual partners. Accordingly, no recognition has been given to Pennsylvania state income taxes in the financial statements for those years.

In October 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The Statement establishes accounting and reporting standards for the impairment or disposal of long-lived assets. The Statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" but retains SFAS No. 121 requirements to recognize an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and to measure an impairment loss as the difference between the carrying amount and fair value of the asset less cost to sell, whether reported in continuing operations or in discontinued operations. In addition, SFAS No. 144 broadens the reporting of discontinued operations to include a component of an entity that has been disposed of or is classified as held for sale. The standard, effective on January 1, 2002, was adopted by the partnership in the fourth quarter of 2001 and had no impact on its financial statements.

On December 7, 2001, the partnership completed the sale-leaseback of its Homer City facilities to third-party lessors for an aggregate purchase price of $1.591 billion, comprised of $782 million in cash and assumption of debt (the fair value of which was $809.3 million). In connection with the sale-leaseback, the partnership used $432 million to repay affiliate interest and debt, paid $73 million to our affiliate for taxes due resulting from the sale, paid $138 million of dividends to its partners, and deposited $139 million in a restricted cash account. The leases the partnership entered into as part of this transaction are referred to as facility leases. The transaction has been accounted for as a lease financing for accounting purposes, which means that the partnership reflects the Homer City facility as

an asset on its balance sheet, although the partnership has no legal ownership, and records the net present value of the future minimum lease payments as lease debt. Under the terms of the 33.67 year leases, the partnership is obligated to make semi-annual lease payments on each April 1 and October 1. The gain on the sale of the Homer City facilities has been deferred and is being amortized over the term of the lease.

The partnership's 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, the partnership's access to most of the cash in the partnership's bank accounts is limited to specific uses set forth in this agreement. The rent payments that the partnership owes 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. If the partnership does not meet specified cash flow coverage ratios while the lease debt is outstanding, it 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.

In order to pay the equity portion of the rent, the partnership is 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 all accrued rent, including both the senior portion and the equity portion of the rent, has been paid and all other required conditions have been met, amounts remaining in the distribution account will be available for distribution to the partners in the partnership, subject to the restrictions on distributions described below.

A restricted cash account was funded at closing of the sale-leaseback transaction in the amount of $139 million. To pay for the initial rent payment, $8 million was subsequently released. The amount in the account will be available for payments due on the equity portion of lease rent, unless there is a default in the payment of the senior portion of lease rent, in which case the amount will be available to pay such senior portion of the lease rent. The release of funds from this restricted cash account will not be subject to any conditions except that no event of default shall have occurred or be continuing.

The following table summarizes our future commitments under the facility leases at December 31, 2001.

Years Ending December 31,
2002	$	175,000
2003		173,957
2004		142,149
2005		151,895
2006		151,615
Thereafter		2,583,278

Total future commitments	$	3,377,894
Amount representing interest		(1,800,577	)

Net Commitments	$	1,577,317

The payments due under the facility leases are generally higher in April and lower in October of each year. In order to more effectively match the partnership's cash flow, which is higher during the summer months when energy prices are higher, the partnership has entered into a swap agreement with a bank. 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. 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 implicit interest rate included in the swap is LIBOR during periods that the partnership has a net deposit with the bank, and LIBOR plus 5% during periods that the partnership has a net loan with the bank.

Under the participation agreements entered into as part of the sale-leaseback transaction, the partnership's 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, the partnership's ability to, among other things, merge, consolidate or sell its assets, create liens on its properties or assets, enter into non-permitted trading activities, enter into transactions with its affiliates, incur indebtedness, create, incur, assume or suffer to exist guarantees or contingent obligations, make restricted payments to its partners, make capital expenditures, own subsidiaries, liquidate or dissolve, engage in non-permitted business activities, sublease the partnership's leasehold interests in the facilities or make improvements to the facilities. Accordingly, the partnership's liquidity is substantially based on its ability to generate cash flow from operations. If the partnership is unable to generate cash flow from operations, it will have limited ability to obtain additional capital unless its partners provide additional funding, although they are under no legal obligation to do so.

At December 31, 2001 and 2000, property, plant and equipment consisted of the following:

	2001			2000
Land	$	4,250		$	4,250
Power plant facilities and equipment		—			1,367,422
Power plant and equipment under lease financing		1,591,318			—
Leasehold improvements		661			—
Emission allowances		438,068			438,068
Construction in progress		—			223,207
Equipment, furniture and fixtures		8,234			7,218

		2,042,531			2,040,165
Accumulated depreciation and amortization		(38,131	)		(84,273	)

Property, plant and equipment, net	$	2,004,400		$	1,955,892

As a result of the sale-leaseback transaction on December 7, 2001, a majority of the power plant facilities and equipment were classified as power plant and equipment under lease financing. The partnership recorded amortization expense related to the leased facilities of $3.1 million for the year ended December 31, 2001. Accumulated amortization related to the leased facilities was $3.1 million at December 31, 2001.

In order to initially effect the acquisition in 1999, Edison Mission Holdings entered into an $800 million initial financing (the "Acquisition Facility"), a $250 million construction loan (the "Environmental Capital Improvements Facility") that would be drawn as needed, and a $50 million line of credit (the "Working Capital Facility"). Amounts borrowed under the Acquisition Facility, the Environmental Capital Improvements Facility and the Working Capital Facility bear interest at variable Eurodollar rates or Base rates, at the option of the partnership. The financing received by Edison Mission Holdings under the Acquisition Facility as well as the Environmental Capital Improvements Facility due 2004 were loaned to Edison Mission Finance under a subordinated loan agreement (the "Finance Subordinated Loan"). Edison Mission Finance then loaned the same amounts to the partnership under a subordinated loan agreement (the "Subordinated Loan"). Interest rates and other charges as well as maturity dates associated with the Subordinated Loan mirrored the associated debt at Edison Mission Holdings.

On May 27, 1999, the Acquisition Facility was replaced with $300 million aggregate principal amount of 8.137% senior secured bonds due 2019 and $530 million aggregate principal amount of 8.734% senior secured bonds due 2026 (collectively, the "Senior Secured Bonds"). Proceeds from the Senior Secured Bonds were loaned by Edison Mission Holdings to Edison Mission Finance and subsequently from Edison Mission Finance to the partnership, under the Subordinated Loan. These proceeds were then used by the partnership to repay $800 million under the Subordinated Loan and make a $30 million distribution to Chestnut Ridge Energy and Mission Energy Westside.

The remaining cost of the acquisition in 1999, as well as initial operating cash, totaling $1.1 billion, was funded through an equity contribution from Edison Mission Energy to Edison Mission Holdings. Edison Mission Holdings subsequently contributed approximately the same amount to Edison Mission Finance, which subsequently loaned the amount to the partnership under a subordinated revolving loan agreement (the "Revolver"). The Revolver bears interest at a fixed rate of 8.0% on outstanding amounts and terminates on March 18, 2014. The partnership owed approximately $606 million and $789 million under the Revolver at December 31, 2001 and 2000, respectively.

In December 2001, the partnership settled the Subordinated Loan with Edison Mission Finance through the assumption of the Senior Secured Bonds by the third-party lessors as part of the purchase price of the facilities and the release of the partnership's guaranty of such debt. The partnership used $432 million from the proceeds of the sale-leaseback of the Homer City facilities (see Note 3. Sale-Leaseback Transaction) to repay a portion of the interest and principal on the Revolver. Accordingly, the remaining intercompany loans at December 31, 2001 are under the Revolver. The partnership is restricted under the participation agreements entered into as a part of the sale-leaseback transaction from making any payments under this facility unless specified conditions are met.

The partnership incurred interest costs related to its affiliate debt of $140.8 million, $147.4 million and $104.2 million for the years ended December 31, 2001, 2000 and 1999, respectively.

The partnership's risk management policy allows for the use of derivative financial instruments through its marketing affiliate to limit financial exposure to energy prices for non-trading purposes. Use of these instruments exposes the partnership 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 the partnership's risk management policies. Policies are in place which limit the amount of total net exposure the partnership 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. The partnership's marketing affiliate performs a series of "value at risk" analyses in its daily business to measure, monitor and control the partnership's overall market risk exposure. The use of value at risk analysis allows the partnership 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 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, the partnership's 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 used for price risk management activities by instrument type:

		December 31,
		2001		2000
Commodity price:
	Forwards	$	35,881	$	(117,803	)
	Options		—		1,811
	Swaps		—		(892	)

Income tax expense includes the current tax liability from operations and the change in deferred income taxes during the year. The components of the net accumulated deferred income tax liability were:

		Years Ended December 31,
		2001		2000
Deferred tax assets
	State tax deduction	$	2,594	$	1,583

		$	2,594	$	1,583

Deferred tax liabilities
	Basis differences	$	9,001	$	60,525
	Other		199		199

			9,200		60,724

Deferred tax liability, net		$	6,606	$	59,141

The provision (benefit) for income taxes before extraordinary item is comprised of the following:

			Years Ended December 31,
			2001			2000			1999
Current
	Federal		$	61,269		$	(27,605	)	$	(24,227	)
	State			13,113			(3,201	)		(2,260	)

		Total current		74,382			(30,806	)		(26,487	)

Deferred
	Federal			(46,511	)		25,897			25,521
	State			(6,024	)		4,518			3,205

		Total deferred		(52,535	)		30,415			28,726

Provision (benefit) for income taxes			$	21,847		$	(391	)	$	2,239

Income tax provision (benefit) is included in the statement of income as follows:

		Years Ended December 31,
		2001		2000			1999
Income (loss) before extraordinary item		$	21,847	$	(391	)	$	2,239
Extraordinary gain (loss)			4,393		—			(2,082	)

	Total	$	26,240	$	(391	)	$	157

The components of the deferred tax provision, which arise from timing differences between financial and tax reporting, are presented below:

		Years Ended December 31,
		2001			2000			1999
Basis differences		$	(51,524	)	$	31,790		$	28,735
State tax deduction			(1,011	)		(1,375	)		(208	)
Other			—			—			199

	Total deferred provision	$	(52,535	)	$	30,415		$	28,726

Employees of the partnership are eligible for various benefit plans of Edison International.

The partnership maintains a pension plan specifically for the benefit of its union employees. The partnership's non-union employees participate in the Edison International pension plan. Both plans are noncontributory, defined benefit pension plans and cover employees who fulfill minimum service requirements. There are no prior service costs for the plans.

A portion of the partnership's non-union employees retiring at or after age 55 with at least ten years of service are eligible for postretirement health care, dental, life insurance and other benefits paid in part by the partnership. Eligibility depends on a number of factors, including the employee's hire date. Employees in union-represented positions are covered by a collective bargaining agreement which is due to expire May 14, 2003. Under this agreement, a portion of these employees that retire prior to May 14, 2002 are covered under the postretirement benefit plans of GPU Inc., their employer prior to the partnership's acquisition of the facilities in 1999. The partnership has accounted for postretirement benefit obligations on the basis of a substantive plan under Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pension" (SFAS No. 106). A substantive plan means that the partnership is assuming for accounting purposes that it will provide postretirement benefits to union-represented employees following the conclusion of negotiations to replace the current benefits agreement, even though the partnership has no legal obligation to do so. If the partnership adopts a postretirement benefit plan for union-represented employees substantially the same as provided under the current GPU Inc. plan, the partnership would record an adjustment to its prior service costs, if applicable, and amortize the impact over the estimated remaining service of covered employees. If no postretirement benefits are provided, the partnership would treat this as a plan termination under SFAS No. 106 and record a gain during 2003. At the present time, the partnership cannot predict the outcome of any negotiations related to this benefit plan.

For the non-union plan, the assumed rate of future increases in the per-capita cost of health care benefits is 10.5% for 2002, gradually decreasing to 5% for 2008 and beyond. Increasing the health care cost trend rate by one percentage point would increase the accumulated obligation as of December 31, 2001, by $462,000 and annual aggregate service and interest costs by $50,000. Decreasing the health care cost trend rate by one percentage point would decrease the accumulated obligation as of December 31, 2001, by $363,000 and annual aggregate service and interest costs by $38,000.

For the union plan, the assumed rate of future increases in the per-capita cost of health care benefits is 10.5% for 2002, gradually decreasing to 5% for 2008 and beyond. Increasing the health care

cost trend rate by one percentage point would increase the accumulated obligation as of December 31, 2001, by $1,782,000 and annual aggregate service and interest costs by $219,000. Decreasing the health care cost trend rate by one percentage point would decrease the accumulated obligation as of December 31, 2001, by $1,469,000 and annual aggregate service and interest costs by $180,000.

A 401(k) plan is maintained to supplement eligible employees' retirement income. The partnership matches 100 percent of non-union employee contributions up to 6 percent of such employees' annual compensation. The partnership also matches 65 percent of contributions made by union employees, up to 2.6 percent of annual compensation. Employer contributions vest 20 percent per year. Contribution expense for the years ended December 31, 2001, 2000 and 1999 was $440,000, $406,000 and $352,000, respectively.

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.

Prior to the partnership's purchase of the Homer City plant, the Environmental Protection Agency requested information from the prior owners of the plant concerning physical changes at the plant. 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.

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 its 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 they plan no further action.

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 has 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 $15,000 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 is evaluating options for permanent treatment of the Dixon Run No. 3 discharge, including a passive system involving wetlands treatment. The total cost of a passive treatment system is estimated to be $1 million, but its operational costs are considerably less than those of a conventional chemical treatment system.

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. Should Helvetia default on its treatment obligations, the government may attempt to require the partnership to fund these commitments.

The partnership has entered into several fuel purchase agreements with various third-party suppliers for the purchase of bituminous steam coal and fuel oil. These contracts call for the purchase of a minimum quantity over the term of the contracts, which extend from one to six years from December 31, 2001, with an option at the partnership's discretion to purchase additional amounts as stated in the agreements. At December 31, 2001, based on the contract provisions that consist of fixed prices, subject to adjustment clauses in certain cases, these minimum commitments are currently estimated to aggregate $472 million over the duration of the contracts summarized as follows: 2002—$160 million; 2003—$99 million; 2004—$90 million; 2005—$67 million; 2006—$40 million; and thereafter—$16 million.

The partnership has 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 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 $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 "—Note 14. Subsequent Event" for further discussion of this event. The selective catalytic reduction system on Units 1 and 2 are scheduled to be installed in 2002. The partnership expects to spend approximately $17.8 million during 2002 on the remaining capital expenditures related to these improvements.

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.

Our 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.

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 $1.25 billion. Under the terms of the facility leases, the partnership is 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 the partnership will continue to monitor developments in the property insurance marketplace.

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.

The partnership employed 257 employees in Pennsylvania, 191 of whom are covered by a collective bargaining agreement, at December 31, 2001. The collective bargaining agreement, which also includes a benefit agreement, is due to expire on May 14, 2003.

The partnership had several operating leases in place relating mainly to flue gas conditioning equipment and trucks. At December 31, 2001, the future operating lease commitments were as follows:

Years Ending December 31,
2002	$	411
2003		362
2004		310
2005		173
2006		38

Total future commitments	$	1,294

Operating lease expense amounted to $626,000, $711,000 and $891,000 in 2001, 2000 and 1999, respectively.

The partnership has 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, the partnership entered into an option for installed capacity, and five transactions, including the exercise of the aforementioned option, for installed capacity with its 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.

The partnership entered into several transactions in 2001 through its 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.

The partnership 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, the partnership pays 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.

The partnership has obtained financing from an affiliate in connection with its acquisition of the Homer City facilities. See "—Note 5. Long-Term Debt" for details of financing with the partnership's affiliates.

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 the partnership, 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). The partnership participates in a common payroll and benefit program with all Edison International employees. In addition, the partnership is billed for any direct labor and out-of-pocket expenses for services directly requested for the benefit of the partnership. The partnership believes the allocation methodologies are reasonable. The partnership 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.

The partnership participates in the insurance program of Edison International, including property, general liability, workers compensation and various other specialty policies. The partnership's insurance premiums are generally based on its 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, the partnership is entitled to receive a premium refund to the extent that its loss experience is less than estimated.

The partnership has 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.

Historically, the partnership has not been charged for an allocation of the Chicago Office of Edison Mission Energy's Americas Region since its inception in late 1999 due to its principal focus on power plants in Illinois. The Chicago Office has technical and managerial responsibility for the partnership's operations. However, the partnership may be charged in the future for a share of these costs. If these costs were allocated to the partnership, they would be recorded as a non-cash charge against the partnership's operations as an in-kind contribution of services through its parent. Accordingly, there would be no cash impact of an allocation of such costs on the partnership's operations. The partnership does not believe that it would incur a material amount of additional costs to operate its Homer City plant on the basis of an unaffiliated relationship with Edison Mission Energy.

2000	First		Second		Third(i)		Fourth
Operating revenues	$	97,616		$	103,012		$	131,049	$	89,692		$	421,369
Operating income		28,849			27,656			57,311		19,006			132,822
Provision (benefit) for income taxes		(2,208	)		(2,106	)		8,964		(5,041	)		(391	)
Net income (loss)		(3,417	)		(5,317	)		13,573		(8,011	)		(3,172	)

All powers to control and manage our business and affairs are exclusively vested in our general partner, Mission Energy Westside Inc., a California corporation and wholly-owned subsidiary of Edison Mission Holdings Co., which in turn is a wholly-owned subsidiary of Edison Mission Energy. The members of Mission Energy Westside's current board of directors are elected by, and serve until their successors are elected by, Edison Mission Holdings. All officers are elected from time to time by Mission Energy Westside's board of directors and hold office at its discretion. Mission Energy Westside's board of directors currently contains five members. The board of directors of Mission Energy Westside may elect to appoint additional directors from time to time.

Listed below are the current directors and the executive officers of Mission Energy Westside and their ages and positions as of March 22, 2002.

Name	Age	Position	Position Held Continuously Since
Georgia R. Nelson	52	Director, President	January 2000
John K. Deshong	48	Director, Vice President	August 2000
Ronald L. Litzinger	42	Director, Vice President	January 2000
Kevin M. Smith	44	Director, Treasurer and Vice President	April 1998
Dean A. Christiansen	42	Director	December 2001
Raymond W. Vickers	59	Director	March 1999
Paul C. Gracey, Jr.	42	Vice President and General Counsel	June 2000

Set forth below are the principal occupations and business activities of the directors and executive officers of Mission Energy Westside for the past five years, in addition to their positions indicated above.

Ms. Nelson has been General Manager, Americas Region of Edison Mission Energy since January 2002. Ms. Nelson has been Senior Vice President of Edison Mission Energy since January 1996 and has been President of Midwest Generation EME, LLC since May 1999. From January 1996 until June 1999, Ms. Nelson was Senior Vice President, Worldwide Operations. Ms. Nelson was Division President of Edison Mission Energy's Americas region from January 1996 to January 1998.

Mr. Deshong has been Vice President, Tax of Edison Mission Energy since June 2000. From November 1998 until June 2000, Mr. Deshong was Regional Vice President—Tax of Edison Mission Energy's Americas Region. Mr. Deshong has served as Director, Tax Planning & Special Projects to Edison Mission Energy from April 1997 to November 1998. Prior to joining Edison Mission Energy, Mr. Deshong was Director of Tax at United States Enrichment Corporation from December 1995 to April 1997.

Mr. Litzinger has been Senior Vice President and Chief Technical Officer of Edison Mission Energy since January 2002. From June 1999 to January 2002, Mr. Litzinger was Senior Vice President, Worldwide Operations, of Edison Mission Energy. Mr. Litzinger served as Vice President—O&M Business Development from December 1998 to May 1999. Mr. Litzinger has been with Edison Mission Energy since November 1995, serving as both Regional Vice President, O&M Business Development and Manager, O&M Business Development until December 1998.

Mr. Smith has been Senior Vice President and Chief Financial Officer of Edison Mission Energy since May 1999 and was Regional Vice President—Finance of Edison Mission Energy's Americas Region from March 1998 until September 1999. Mr. Smith served as Treasurer of Edison Mission Energy from September 1992 to February 2000 and was elected to Vice President in 1994.

Mr. Christiansen has been Director of Edison Mission Energy since January 2001 and serves as Edison Mission Energy's independent director. Mr. Christiansen has been President of Lord Securities since October 2000 and has been President of Acacia Capital since May 1990. Mr. Christiansen has been Director of Capital Markets Engineering & Trading, New York since August 1999 and has been Director of Structural Concepts Corporation of Muskegon, Michigan since May 1995.

Mr. Vickers has been Senior Vice President and General Counsel of Edison Mission Energy since March 1999. Prior to joining Edison Mission Energy, Mr. Vickers was a partner with the law firm of Skadden, Arps, Slate, Meagher & Flom since 1989.

Mr. Gracey has been Vice President of Edison Mission Energy since May 1998, and has been Vice President and General Counsel of Midwest Generation EME, LLC since June 2000. From July 1996 until May 2000, Mr. Gracey was Regional Vice President—Legal of Edison Mission Energy's European Region. From August 1993 until May 2000, Mr. Gracey was the Director and General Counsel of Edison Mission Energy's European Region. Mr. Gracey has been a lawyer with Edison Mission Energy since 1992.

The officers of Mission Energy Westside receive no compensation from us for their services as officers.

Set forth below is certain information regarding each person who is known by us to be a beneficial owner.

Title of Class		Name and Address of Beneficial Owner		Amount and Nature of Beneficial Owner		Percent of Class
Partnership interests		Mission Energy Westside Inc. 18101 Von Karman Avenue Suite 1700 Irvine, CA 92612		General partner with exclusive voting and investment power		0.1	%

Our indirect parent, Edison Mission Holdings, has pledged the shares of the capital stock of our general partner, Mission Energy Westside Inc., as collateral for our performance under our sale-leaseback obligation. Upon termination of the facility leases, the owner lessors may foreclose on this pledge and could own Mission Energy Westside and be able to exercise all the powers of general partner.

In July 1999, Edison Mission Energy, our indirect parent, made an interest-free loan to Georgia R. Nelson, Director and President of Mission Energy Westside Inc., in the amount of $179,800 in exchange for a note executed by Ms. Nelson and payable 365 days following the conclusion of her assignment in Chicago, Illinois.

Exhibit No.		Description
3.1		EME Homer City Generation L.P. Agreement of Limited Partnership incorporated by reference to Exhibit 3.13 to Edison Mission Holding Co.'s registration statement on Form S-4 filed with the Securities and Exchange Commission on December 3, 1999 (File No. 333-92047).
3.2		Amended and Restated Agreement of Limited Partnership of EME Homer City Generation L.P., dated as of December 7, 2001.*
4.1		Indenture, dated as of May 27, 1999, between Edison Mission Holdings Co. and United States Trust Company of New York, as Trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Holdings Co.'s registration statement on Form S-4 filed with the Securities and Exchange Commission on December 3, 1999 (File No. 333-92047).
4.1.1		First Amended and Restated Indenture, dated as of December 7, 2001 among Homer City Funding LLC and The Bank of New York, as successor trustee to United States Trust Company of New York.*
4.1.2		Form of 8.137% Senior Secured Bond due 2019 (included in Exhibit 4.1.1). *
4.1.3		Form of 8.734% Senior Secured Bond due 2026 (included in Exhibit 4.1.1). *
4.1.4		Assumption Agreement, dated as of December 7, 2001, among EME Homer City Generation, L.P., Homer City OL1 LLC, Homer City OL2 LLC, Homer City OL3 LLC, Homer City OL4 LLC, Homer City OL5 LLC, Homer City OL6 LLC, Homer City OL7 LLC, Homer City OL8 LLC, Homer City Funding LLC and The Bank of New York as successor to United States Trust Company of New York.*
4.2		Indenture of Trust and Security Agreement, dated as of December 7, 2001, between Homer City OL1 LLC, The Bank of New York, as Lease Indenture Trustee and Security Agent.*

Pursuant to the requirements of Section 13 or 15(d) 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.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

		Equivalent Availability Factor (%)	Net Heat Rate (Btu/kWh)	Fuel and O&M Costs ($/MWh)
Units 1, 2 and 3—1,884 MW
	2001	87.39	9,880	18.32
	2000	80.22	9,928	19.51
	1999*	86.81	9,962	17.90
	1998*	89.79	9,793	17.12
	1997*	85.83	9,804	18.17
	5-Year Average	86.01	9,873	18.20

	Years Ended December 31,
	2001			2000			1999
	(in thousands)
INCOME STATEMENT DATA
Operating revenues	$	494,008		$	421,369		$	325,752
Operating expenses		304,443			288,547			218,688

Operating income		189,565			132,822			107,064
Interest and other income (loss)		(412	)		2,269			1,040
Interest expense		(139,038	)		(138,654	)		(103,814	)

Income (loss) before income taxes and extraordinary item		50,115			(3,563	)		4,290
Provision (benefit) for income taxes before extraordinary item		21,847			(391	)		2,239

Income (loss) before extraordinary item		28,268			(3,172	)		2,051
Extraordinary gain (loss) on early extinguishment of debt, net of tax of $4,393 and ($2,082)		5,701			—			(2,865	)

Net income (loss)	$	33,969		$	(3,172	)	$	(814	)

	December 31,
	2001		2000		1999
	(in thousands)
BALANCE SHEET DATA
Assets	$	2,336,648	$	2,156,559	$	2,021,858
Current liabilities		114,074		81,811		74,701
Long-term debt to affiliates		605,591		1,801,167		1,700,819
Lease financing		1,498,697		—		—
Other long-term obligations		25,502		76,766		46,351
Partners' equity		92,784		196,815		199,987

	Years Ended December 31,
	2001			2000			1999
	(in thousands)
CASH FLOW DATA
Cash provided by (used in) operating activities	$	(17,211	)	$	17,000		$	84,597
Cash provided by (used in) financing activities		(531,735	)		99,242			1,883,473
Cash provided by (used in) investing activities		568,331			(141,580	)		(1,923,616	)

		2002		2003		2004		2005		2006		Thereafter		Total
		(in millions)
Contractual Obligations
Long-term debt to affiliate		$	—	$	—	$	—	$	—	$	—	$	605.6	$	605.6
Lease financing			175.0		174.0		142.1		151.9		151.6		2,583.3		3,377.9
Operating lease obligations			0.4		0.4		0.3		0.2		—		—		1.3
Fuel supply contracts			160.4		98.5		90.4		66.8		39.8		16.5		472.4

	Total Contractual Cash Obligations	$	335.8	$	272.9	$	232.8	$	218.9	$	191.4	$	3,205.4	$	4,457.2

Commercial Commitments
Environmental improvements		$	17.8	$	—	$	—	$	—	$	—	$	—	$	17.8

Financial Statements:
	Report of Independent Public Accountants	36
	Balance Sheets at December 31, 2001 and 2000	37
	Statements of Income (Loss) for the years ended December 31, 2001, 2000 and 1999	38
	Statements of Comprehensive Income (Loss) for the years ended December 31, 2001, 2000 and 1999	39
	Statements of Partners' Equity for the years ended December 31, 2001, 2000 and 1999	40
	Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999	41
	Notes to Financial Statements	42

			December 31,
			2001		2000
Assets
Current Assets
	Cash and cash equivalents		$	38,501	$	19,116
	Due from affiliates			76,047		128,927
	Fuel inventory			24,751		14,993
	Spare parts inventory			22,725		23,582
	Deposits			36,992		—
	Assets under price risk management			14		—
	Other current assets			2,701		2,758

		Total current assets		201,731		189,376

Property, Plant and Equipment				2,042,531		2,040,165
	Less accumulated depreciation and amortization			38,131		84,273

		Net property, plant and equipment		2,004,400		1,955,892

Deferred financing charges, net				—		11,291
Restricted cash				130,517		—

Total Assets			$	2,336,648	$	2,156,559

Liabilities and Partners' Equity
Current Liabilities
	Accounts payable		$	2,976	$	16,479
	Accrued liabilities			20,296		32,195
	Interest payable			8,016		—
	Interest payable to affiliates			4,166		32,668
	Current portion of lease financing			78,620		—
	Other current liabilities			—		469

		Total current liabilities		114,074		81,811

Long-term debt to affiliate				605,591		1,801,167
Lease financing, net of current portion				1,498,697		—
Deferred taxes				6,606		59,141
Benefit plans and other				18,896		17,625

Total Liabilities				2,243,864		1,959,744

Commitments and Contingencies (Notes 3, 9 and 10)
Partners' Equity				92,784		196,815

Total Liabilities and Partners' Equity			$	2,336,648	$	2,156,559

			Chestnut Ridge Energy Company			Mission Energy Westside Inc.			Total Partners' Equity
Balance at January 1, 1999			$	—		$	—		$	—
	Net loss			(807	)		(7	)		(814	)
	Cash contribution			270,576			2,733			273,309
	Cash distributions			(71,782	)		(726	)		(72,508	)

Balance at December 31, 1999				197,987			2,000			199,987

	Net loss			(3,141	)		(31	)		(3,172	)

Balance at December 31, 2000				194,846			1,969			196,815

	Net income			33,623			346			33,969
	Cash distributions			(136,600	)		(1,400	)		(138,000	)
	Unrealized gains (losses) on derivatives qualified as cash flow hedges:
		Cumulative effect of change in accounting for derivatives, net of income tax benefit of $58,234		(85,863	)		(867	)		(86,730	)
		Other unrealized holding gains arising during period, net of income tax expense of $46,647		68,778			695			69,473
		Reclassification adjustment for losses included in net income, net of income tax benefit of $11,587		17,085			172			17,257

Balance at December 31, 2001			$	91,869		$	915		$	92,784

			Years Ended December 31,
			Union Plan						Non-Union Plan
			2001			2000			2001			2000
Change in Benefit Obligation
	Benefit obligation at beginning of year		$	9,537		$	6,783		$	1,416		$	865
	Service cost			849			719			263			291
	Interest cost			685			578			111			78
	Actuarial loss			371			1,457			112			182
	Benefits paid			(1	)		—			—			—

		Benefit obligation at end of year	$	11,441		$	9,537		$	1,902		$	1,416

Change in Plan Assets
	Fair value of plan assets at beginning of year		$	2,098		$	104		$	—		$	—
	Actual return on plan assets			(71	)		(126	)		—			—
	Employer contributions			2,012			2,120			—			—
	Benefits paid			(1	)		—			—			—

		Fair value of plan assets at end of year	$	4,038		$	2,098		$	—		$	—

Funded status			$	(7,403	)	$	(7,439	)	$	(1,902	)	$	(1,416	)
Unrecognized net loss				2,359			1,652			177			78

Pension liability			$	(5,044	)	$	(5,787	)	$	(1,725	)	$	(1,338	)

Discount rate				7.00	%		7.25	%		7.00	%		7.25	%
Rate of compensation increase				5.00	%		5.00	%		5.00	%		5.00	%
Expected return on plan assets				8.50	%		7.50	%		8.50	%		8.50	%

2001	First		Second			Third(i)		Fourth			Total
Operating revenues	$	128,517	$	105,695		$	153,985	$	105,811		$	494,008
Operating income		54,810		33,008			74,404		27,343			189,565
Provision (benefit) for income taxes		7,541		(642	)		15,872		(924	)		21,847
Extraordinary gain, net of tax of $4,393		—		—			—		5,701			5,701
Net income (loss)		11,513		(1,588	)		24,850		(806	)		33,969

(a)(1)		List of Financial Statements
		See Index to Financial Statements at Item 8 of this report.
(2)		List of Financial Statement Schedules
		Schedules have been omitted since the required information is not present in amounts sufficient to require submission of the schedule, or because the required information is included in the financial statements or notes thereto referenced in (a)(1) above.
(b)		Reports on Form 8-K
		EME Homer City Generation L.P. filed the following reports on Form 8-K and Form 8-K/A during the quarter ended December 31, 2001.

	Date of Report	Dated Filed	Item(s) Reported
	November 21, 2001	November 21, 2001	5,7
	December 5, 2001	December 5, 2001	5,7
	December 5, 2001	December 5, 2001	5
(c)	Exhibits

4.2.1		Schedule identifying substantially identical agreements to Indenture of Trust and Security Agreement constituting Exhibit 4.2 hereto.*
4.2.2		Form of Initial Lessor Note (included in Exhibit 4.2).*
4.3		Facility Lease Agreement, dated as of December 7, 2001, between Homer City OL1 LLC and EME Homer City Generation L.P.*
4.3.1		Schedule identifying substantially identical agreements to Facility Lease Agreement constituting Exhibit 4.3 hereto.*
4.4		Participation Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P., Homer City OL1 LLC, as Facility Lessor and Ground Lessee, Wells Fargo Bank Northwest National Association, General Electric Capital Corporation, The Bank of New York as the Security Agent, The Bank of New York as Lease Indenture Trustee, Homer City Funding LLC and The Bank of New York as Bondholder Trustee.*
4.4.1		Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 4.4 hereto.*
4.5		Owner Lessor Subordination Agreement, dated as of December 7, 2001, by and among Homer City OL1 LLC as the Owner Lessor, General Electric Capital Corporation as the Owner Participant and The Bank of New York, as the Lease Indenture Trustee.*
4.5.1		Schedule identifying substantially identical agreements to Owner Lessor Subordination Agreement constituting Exhibit 4.5 hereto.*
4.6		Lease Subordination Agreement, dated as of December 7, 2001, by and among Homer City OL1 LLC, as the Owner Lessor, GE Capital Corporation as the Owner Participant, EME Homer City Generation L.P. as Facility Lessee and The Bank of New York as Security Agent.*
4.6.1		Schedule identifying substantially identical agreements to Lease Subordination Agreement constituting Exhibit 4.6 hereto.*
4.7		Pledge and Collateral Agreement made by Edison Mission Holdings Co. in favor of The Bank of New York, as successor to United States Trust Company of New York, as Collateral Agent, dated as of December 7, 2001.*
4.8		Assumption and Release Agreement, dated as of December 7, 2001, among Edison Mission Holdings Co., Edison Mission Finance Co., EME Homer City Generation L.P. and The Bank of New York (as successor in interest to United States Trust Company of New York), as Bondholder Trustee and Collateral Agent.*
4.9		Open-End Mortgage, Security Agreement and Assignment of Rents, dated as of December 7, 2001, among Homer City OLI LLC, as the Owner Lessor to The Bank of New York, as Security Agent and Mortgagee.*
10.1		Exchange and Registration Rights Agreement, dated as of May 27, 1999, by and among the Initial Purchasers named therein, the Guarantors named therein and Edison Mission Holdings Co., incorporated by reference to Exhibit 10.1 to Edison Mission Holding Co.'s registration statement on Form S-4 to the Securities and Exchange Commission on December 3, 1999 (File No. 333-92047).

10.12		Transition Power Purchase Agreement, dated August 1, 1998, between New York State Electric & Gas Corporation and Mission Energy Westside Inc., incorporated by reference to Exhibit 10.52 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
10.13		Transition Power Purchase Agreement, dated August 1, 1998, between Pennsylvania Electric Company and Mission Energy Westside Inc., incorporated by reference to Exhibit 10.53 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
10.14		Guarantee, dated August 1, 1998, between Edison Mission Energy, Pennsylvania Electric Company, NGE Generation, Inc. and New York State Electric & Gas Corporation, incorporated by reference to Exhibit 10.54 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
10.15		Credit Agreement, dated March 18, 1999, among Edison Mission Holdings Co. and Certain Commercial Lending Institutions, and Citicorp USA, Inc., incorporated by reference to Exhibit 10.55 to Edison Mission Energy's Form 8-K dated March 18, 1999.
10.16		Guarantee and Collateral Agreement made by Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside Inc., EME Homer City Generation L.P. and Edison Mission Energy in favor of United States Trust Company of New York, dated as of March 18, 1999, incorporated by reference to Exhibit 10.56 to Edison Mission Energy's Form 8-K dated March 18, 1999.
10.16.1		Amendment No. 1 to the Guarantee and Collateral Agreement, dated May 27, 1999, between Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Company, Mission Energy Westside Inc., EME Homer City Generation L.P. and Edison Mission Energy in favor of United States Trust Company of New York, incorporated by reference to Exhibit 10.56.1 to Amendment No. 1 of Edison Mission Holdings Co.'s registration statement on Form S-4 filed with the Securities and Exchange Commission on February 8, 2000 (File No. 333-92047).
10.16.2		Open-End Mortgage, Security Agreement and Assignment of Lease and Rents, dated March 18, 1999, from EME Homer City Generation L.P. to United States Trust Company of New York, incorporated by reference to Exhibit 10.56.2 to Amendment No. 1 of Edison Mission Holdings Co.'s registration statement on Form S-4 filed with the Securities and Exchange Commission on February 8, 2000 (File No. 333-92047).
10.16.3		Amendment No. 1 to the Open-End Mortgage, Security Agreement and Assignment of Leases and Rents, dated May 27, 1999, from EME Homer City Generation L.P. to United States Trust Company of New York, incorporated by reference to Exhibit 10.56.3 to Amendment No. 1 of Edison Mission Holdings Co.'s registration statement on Form S-4 filed with the Securities and Exchange Commission on February 8, 2000 (File No. 333-92047).
10.16.4		Amended and Restated Guarantee and Collateral Agreement, dated as of December 7, 2001, made by EME Homer City Generation L.P. in favor of The Bank of New York as successor to United States Trust Company of New York, as Collateral Agent.*

10.17		Collateral Agency and Intercreditor Agreement among Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside Inc., EME Homer City Generation L.P., The Secured Parties' Representative, Citicorp USA, Inc., as Administrative Agent and United States Trust Company of New York, as Collateral Agent, dated as of March 18, 1999, incorporated by reference to Exhibit 10.57 to Edison Mission Energy's Form 8-K dated March 18, 1999.
10.18		Security Deposit Agreement among Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside Inc., EME Homer City Generation L.P. and United State Trust Company of New York, as Collateral Agent, dated as of March 18, 1999, incorporated by reference to Exhibit 10.58 to Edison Mission Energy's Form 8-K dated March 18, 1999.
10.18.1		Amendment No. 1 to the Security Deposit Agreement, dated May 27, 1999, between Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Company, Mission Energy Westside Inc., EME Homer City Generation L.P. and United States Trust Company of New York, as Collateral Agent, incorporated by reference to Exhibit 10.58.1 to Amendment No. 1 of Edison Mission Holdings Co.'s registration statement on Form S-4 filed with the Securities and Exchange Commission on February 8, 2000 (File No. 333-92047).
10.18.2		Amended and Restated Security Deposit Agreement, dated as of December 7, 2001, among EME Homer City Generation L.P. and The Bank of New York as Collateral Agent.*
10.19		Credit Support Guarantee, dated as of March 18, 1999, made by Edison Mission Energy in favor of United States Trust Company of New York, incorporated by reference to Exhibit 10.59 to Edison Mission Energy's Form 8-K dated March 18, 1999.
10.19.1		Amendment No. 1 to the Credit Support Guarantee, dated May 27, 1999, made by Edison Mission Energy in favor of United States Trust Company of New York, incorporated by reference to Exhibit 10.59.1 to Amendment No. 1 of Edison Mission Holdings Co.'s registration statement on Form S-4 filed with the Securities and Exchange Commission on February 8, 2000 (File No. 333-92047).
10.20		Debt Service Reserve Guarantee, dated as of March 18, 1999, made by Edison Mission Energy in favor of United States Trust Company of New York on behalf of the various financial institutions (Lenders) as are or may become parties to the Credit Agreement, dated as of March 18, 1999, among Edison Mission Holdings Co., the Lenders and Citicorp USA, Inc., incorporated by reference to Exhibit 10.60 to Edison Mission Energy's Form 8-K dated March 18, 1999.
10.20.1		Amendment No. 1 to the Debt Service Reserve Guarantee, dated May 27, 1999, made by Edison Mission Energy in favor of United States Trust Company of New York, incorporated by reference to Exhibit 10.60.1 to Amendment No. 1 of Edison Mission Holdings Co.'s registration statement on Form S-4 filed with the Securities and Exchange Commission on February 8, 2000 (File No. 333-92047).
10.20.2		Amendment No. 2 to the Debt Service Reserve Guarantee, dated as of March 18, 2001, made by Edison Mission Energy in favor of United States Trust Company of New York, incorporated by reference to Exhibit 10.60.2 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2001.

		Arthur Andersen LLP
Orange County, California
March 25, 2002

10.20.3		Bond Debt Service Reserve Guarantee, dated May 27, 1999, made by Edison Mission Energy in favor of United States Trust Company of New York, incorporated by reference to Exhibit 10.60.2 to Amendment No. 1 of Edison Mission Holdings Co.'s registration statement on Form S-4 filed with the Securities and Exchange Commission on February 8, 2000 (File No. 333-92047).
10.21		Credit Agreement, dated March 18, 1999, among Edison Mission Energy and Certain Commercial Lending Institutions, and Citicorp USA Inc., incorporated by reference to Exhibit 10.61 to Edison Mission Energy's Form 8-K dated March 18, 1999.
10.21.1		Amendment One to Credit Agreement, dated as of August 17, 2000, by and among Edison Mission Energy, Certain Commercial Lending Institutions, and Citicorp USA, Inc., as Administrative Agent, incorporated by reference to Exhibit 10.61.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.22		Asset Purchase Agreement, dated August 1, 1998, between Pennsylvania Electric Company, NGE Generation, Inc., New York State Electric & Gas Corporation and Mission Energy Westside, Inc., incorporated by reference to Exhibit 2.4 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
10.23		Intercompany Loan Subordination Agreement, dated March 18, 1999, among Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside Inc., EME Homer City Generation L.P. and United States Trust Company of New York, incorporated by reference to Exhibit 10.60.3 to Amendment No. 2 of Edison Mission Holdings Co.'s registration statement on Form S-4 filed with the Securities and Exchange Commission on February 29, 2000 (File No. 333-92047).
10.23.1		Amended and Restated Intercompany Loan Subordination Agreement, dated as of December 7, 2001, among Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside, Inc., EME Homer City Generation L.P. and The Bank of New York, as successor to United States Trust Company of New York.*
10.27		Designated Account Representative Agreement Relating to the NOx Allowance Program, entered into as of December 7, 2001, by and between EME Homer City Generation L.P., Homer City OL1 LLC, Homer City OL2 LLC, Homer City OL3 LLC, Homer City OL4 LLC, Homer City OL5 LLC, Homer City OL6 LLC, Homer City OL7 LLC and Homer City OL8 LLC.*
10.28		Designated Account Representative Agreement Relating to the Acid Rain Program, entered into as of December 7, 2001, by and between EME Homer City Generation L.P., Homer City OL1 LLC, Homer City OL2 LLC, Homer City OL3 LLC, Homer City OL4 LLC, Homer City OL5 LLC, Homer City OL6 LLC, Homer City OL7 LLC and Homer City OL8 LLC.*
10.29		Assignment Agreement, dated December 7, 2001, between The Bank of New York, EME Homer City Generation L.P., Edison Mission Marketing & Trading, Inc. and Edison Mission Energy Fuel Services, Inc.*
10.30		Debt Service Reserve Letter of Credit and Reimbursement Agreement, dated December 7, 2001, by and among Homer City OL1 LLC, Westdeutsche Landesbank Girozentrale, New York Branch, Credit Suisse First Boston, New York Branch and Westdeutsche Landesbank Girozentrale, New York Branch.*

10.30.1		Schedule identifying substantially identical agreements to the Debt Service Reserve Letter of Credit and Reimbursement Agreement constituting Exhibit 10.30 hereto.*
10.31		Sub-Assignment Agreement, dated as of December 7, 2001, between The Bank of New York, EME Homer City Generation L.P., Edison Mission Marketing & Trading, Inc., and Edison Mission Energy Fuel Services, Inc.*
21		List of Subsidiaries of EME Homer City Generation L.P.*
99		Letter from EME Homer City Generation L.P. Regarding Assurance Letter from Arthur Andersen LLP.*

		EME Homer City Generation L.P. (Registrant)
		By:		/s/ GEORGIA R. NELSON Georgia R. Nelson, President and Director
		Date:		March 28, 2002

Signature	Title	Date

Principal Executive Officer:
/s/ GEORGIA R. NELSON Georgia R. Nelson	President and Director	March 28, 2002
Principal Financial and Accounting Officer:
/s/ KEVIN M. SMITH Kevin M. Smith	Vice President, Treasurer and Director	March 28, 2002
Majority of Board of Directors:
/s/ JOHN K. DESHONG John K. Deshong	Vice President and Director	March 28, 2002
/s/ RONALD L. LITZINGER Ronald L. Litzinger	Vice President and Director	March 28, 2002
/s/ RAYMOND W. VICKERS Raymond W. Vickers	Director	March 28, 2002