Prepared by MERRILL CORPORATION

Edison Mission Holdings Co.
(Exact name of registrant as specified in its charter)

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 /x/ NO / /

Number of shares outstanding of the registrant's Common Stock as of November 13, 2001: 100 shares (all shares held by an affiliate of the registrant).

Item		Page
PART I—Financial Information
1.	Financial Statements	1
2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	9
3.	Quantitative and Qualitative Disclosures About Market Risk	18
PART II—Other Information
6.	Exhibits and Reports on Form 8-K	50
	Signatures	51

EDISON MISSION HOLDINGS CO. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands)

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

EDISON MISSION HOLDINGS CO. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In thousands)

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

EDISON MISSION HOLDINGS CO. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)

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

EDISON MISSION HOLDINGS CO. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

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

EDISON MISSION HOLDINGS CO. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands)

We have made all adjustments, including recurring accruals, that are necessary to present fairly the consolidated financial position and results of operations for the periods covered by this report. The results of operations for the nine months ended September 30, 2001 are not necessarily indicative of the operating results for the full year.

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

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

Effective January 1, 2001, we 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, we recorded all derivatives at fair value unless the derivatives qualified for the normal sales and purchases exception. Our physical fuel contracts qualified under this exception. We did not use this exception for forward sales contracts from our Homer City plant due to the net settlement procedures used by our marketing affiliate with counterparties for the period between January 1, 2001 through June 30, 2001. Forward sales contracts from our Homer City plant 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. We recorded a $61.8 million, after tax, unrealized holding loss upon adoption of this change in accounting principle reflected in accumulated other comprehensive income in the consolidated balance sheet. We recorded a net loss of $482,000 from the ineffective portion of cash flow hedges during the three months ended September 30, 2001. The loss is reflected in income (loss) from price risk management in the consolidated statement of operations.

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, we qualified to use the normal sales and purchases exception for our Homer City forward sales contracts commencing July 1, 2001. Based on this accounting guidance, on July 1, 2001, we eliminated the value of the Homer City forward sale contracts

from our balance sheet. The cumulative effect of this change in accounting is reflected as a $15.5 million decrease in other comprehensive income.

Our subsidiary, EME Homer City Generation L.P. (EME Homer City), has entered into separate transition contracts with Pennsylvania Electric Company (Penelec) and New York State Electric & Gas Corporation (NYSEG), under which EME Homer City may exercise a put option to sell certain quantities of capacity to Penelec and NYSEG, and Penelec and NYSEG may exercise call options to purchase certain quantities of capacity. The terms of the NYSEG Transition Contract continue until December 31, 2002 and the Penelec Transition Contract expired on May 31, 2001. EME Homer City exercised its put options to sell 942 MW of capacity to Penelec for the full period from March 18, 1999 through May 31, 2001 under the Penelec Transition Contract for a price of $49.90/MW-day from March 18, 1999 through May 31, 1999, $59.90/MW-day through May 31, 2000, and $77.40/MW-day through May 31, 2001. EME Homer City has amended the NYSEG Transition Contract and sold 500 MW of capacity to NYSEG through May 31, 2000 for a price of $60.00/MW-day, 370 MW of capacity through September 30, 2000 for $72.17/MW-day, and plans to sell 430 MW of capacity through December 31, 2001 for $72.17/MW-day, 400 MW through April 30, 2002 for $51.00/MW-day and 300 MW through December 31, 2002 for $99.84/MW-day.

The Company has entered into a contract with a marketing affiliate for the sale of energy and capacity produced by the Homer City facilities, which are comprised of three coal-fired electric generating units located near Pittsburgh, Pennsylvania, and related facilities. This contract enables the marketing affiliate to engage in forward sales and hedging transactions to manage the Company's electricity price exposure. Net gains or losses on hedges by the marketing affiliate that are settled are recognized in the same manner as the hedged item. The Company receives the net transaction price on all contracts that are settled. In connection with these agreements, the Company has agreed to provide credit support in the form of guarantees. At September 30, 2001, the Company had executed guarantees totaling $177.4 million.

Pennsylvania Department of Environmental Protection (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 Company would be required to develop abatement plans, which may include the lining of unlined sites. To date, the Homer City facilities' ash disposal site has not shown any signs that would require abatement. Management does not believe that the costs of maintaining and, if necessary, abandoning the ash disposal site will have a material impact on the Company's results of operations or financial position.

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. In May 2001, President Bush issued a directive for a 90-day review of new source review "interpretation and implementation" by the Administrator of the Environmental Protection Agency and the Secretary of the U.S. Department of Energy, which has been extended indefinitely. President Bush also directed the Attorney General to review ongoing new source review legal actions to "ensure" they are "consistent with the Clean Air Act and its regulations." Both actions were recommendations detailed within the Bush administration's "National Energy Policy Task Force Report."

In connection with our purchase of the Homer City facilities on March 18, 1999, 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 filed for bankruptcy, however, it operated the collection and treatment system until May 1999 when 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 has 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 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 Blacklick Creek Watershed Association to develop and operate a collection and treatment system for the Penn Hill No. 2 discharge. The Watershed Association has started construction on the Penn Hill No. 2 system and expects it to be completed in November 2001.

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% after the Penn Hill No. 2 system construction is completed. 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.

Upon acquisition of the Homer City facilities, the Company began major plant improvements consisting primarily of a turnkey pollution control retrofit project. The estimated cost of this project is $270 million, of which $243 million has been incurred prior to September 30, 2001. We expect to spend approximately $15 million for the remainder of 2001 and $12 million in 2002 to complete this project.

The Company has entered into a Coal Cleaning Agreement with Homer City Coal Processing Corp. to operate and maintain a coal-cleaning plant owned by EME Homer City. Under the terms of the agreement, which is scheduled to expire on August 31, 2002, the Company 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 $0.20 to $0.35 per ton of coal processed, depending on the level of tonnage.

Subsidiaries of the Company have entered into Interconnection Agreements with NYSEG and Penelec to provide interconnection services necessary to interconnect the Homer City Station with NYSEG's and Penelec's transmission systems. Unless an Interconnection Agreement is terminated earlier in accordance with its terms, it will terminate on a date mutually agreed to by EME Homer City, 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 to modifications, additions, upgrades or repowering of the Homer City units. EME Homer City is required to compensate NYSEG and Penelec for all reasonable costs associated with any modifications, additions or replacements made to NYSEG's or Penelec's interconnection facilities or transmission systems in connection with any modification, addition or upgrade to the Homer City units.

	Nine Months Ended September 30,
	2001		2000
	(Unaudited)
Cash paid for interest	$	46,349	$	42,784
Cash paid for income taxes		—		—

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

The following discussion contains forward-looking statements that reflect our current expectations and projections about future events based on our knowledge of present facts and circumstances and our assumptions about future events. In this discussion, the words "expects," "believes," "anticipates," "estimates," "intends," "plans" and variations of these words and similar expressions are intended to identify forward-looking statements. These statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. 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 Edison Mission Holdings Co. and its consolidated subsidiaries.

We are a special-purpose California corporation formed on October 7, 1998 for the purpose of facilitating the financing of the acquisition and, through our wholly-owned subsidiaries, acquiring, making improvements to and operating our three coal-fired electric generating units and related facilities. EME Homer City, our indirect subsidiary, acquired the Homer City facilities on March 18, 1999 for a purchase price of approximately $1.8 billion. Although we were incorporated in 1998, we had no significant activity prior to the acquisition of the Homer City facilities.

Edison Mission Energy is our 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 (SEC) and has financial statements that are filed in accordance with rules enacted by the SEC. For more information regarding each of these companies, see their respective Forms 10-K for the year ended December 31, 2000 and other periodic reports filed by them under the Securities and Exchange Act of 1934.

EME Homer City derives revenue from the sale of energy and capacity into the Pennsylvania-New Jersey-Maryland power market (PJM) and the New York independent system operator (NYISO) and from bilateral contracts with power marketers and load serving entities within PJM, NYISO and the surrounding markets. EME Homer City has entered into a contract with a marketing affiliate for the sale of energy and capacity produced by the Homer City facilities, which enables this marketing affiliate to engage in forward sales and hedging. EME Homer City pays the marketing affiliate fees of $0.02/MWh plus emission allowance fees. The net fees earned by the marketing affiliate were $0.1 million and $0.7 million for the third quarter and nine months ended September 30, 2001, respectively, compared to $0.2 million and $1.5 million in the corresponding periods in 2000.

During 2001, EME Homer City entered into three transactions for unforced capacity with our marketing affiliate as follows: 450 MW from June to December 2001, 150 MW from January to December 2002, and 125 MW from January to May 2002. Each was at fair market value for such unforced capacity at the time. Total payments for the three transactions will amount to approximately $25.5 million.

Certain administrative services such as payroll, employee benefit programs, insurance and information technology are shared among all affiliates of our ultimate parent company, Edison International, and the costs of these corporate support services are allocated to all affiliates. The cost of services provided by Edison International, including those related to us, are allocated to Edison Mission Energy 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, Edison International bills Edison Mission Energy for any direct labor and out-of-pocket expenses for services directly requested for our benefit. We believe the allocation methodologies are reasonable.

Historically, we have 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 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.

Operating revenues increased $22.9 million and $56.5 million for the third quarter and nine months ended September 30, 2001, respectively, compared to the corresponding periods in 2000. Energy and capacity sales were made through a contract with a marketing affiliate. Energy and capacity revenue increases were from increased production and higher energy prices. We generated 3,445 GWh and 9,605 GWh of electricity during the third quarter and nine months ended September 30, 2001, respectively, compared to generating 3,341 GWh and 9,091 GWh of electricity in the corresponding periods in 2000. The availability factor for the nine months ended September 30, 2001 was 85.7%, compared to 84.4% for the corresponding period in 2000. 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 (generally referred to as forced outages) maintenance. During the nine months ended September 30, 2001, our forced outage rate was 3.3% compared to 5.1% during the corresponding period in 2000.

The weighted average price for energy was $37.44/MWh during the third quarter of 2001, compared to $34.60/MWh for the same period in 2000. The weighted average price for energy was $35.02/MWh during the first nine months of 2001, compared to $31.58/MWh for the same period in 2000. The increase in the weighted average price for energy is due to higher PJM market prices and higher prices obtained through forward energy contracts.

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

Income (loss) from price risk management activities decreased $5.8 million and $5.7 million for the third quarter and nine months ended September 30, 2001, compared to the corresponding periods in 2000. The decline is due to a reduction in volume and changes in market value of the portion of our power forward purchase and sales contracts that were recorded as derivatives at fair value under SFAS No. 133.

Operating expenses increased $6.0 million and $7.6 million for the third quarter and nine months ended September 30, 2001, respectively, compared to the corresponding periods in 2000. Operating expenses consisted of expenses for fuel, plant operations, depreciation, and administrative and general expenses. The change in components of operating expenses is discussed below.

production offset by lower average fuel prices. The average price of coal per ton was $27.24 for the nine months ended September 30, 2001, compared to $28.64 for the same period in 2000. The average price decreased due to changes in the type of coal used in operations. The 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 is supplied under existing contracts with regional mines that are located within approximately 100 miles of the facilities, while the remainder is purchased on the spot market. The coal for these units that is purchased from local mines is cleaned by the coal-cleaning facility to reduce sulfur and ash content. Unit 3 currently utilizes lower sulfur coal that is blended at an on-site coal blending facility. As we complete the Environmental Improvements, we plan to eliminate the lower sulfur coal at Unit 3 (as our sulfur emissions will be reduced through use of the Environmental Improvements) that will reduce our fuel costs. The lower fuel costs will be partially offset by higher depreciation expense from the Environmental Improvements and interest expense (currently being capitalized).

Plant operations costs increased $4.0 million and $0.4 million in the third quarter and nine months ended September 30, 2001, respectively, compared to the same periods in 2000. Plant operations costs include labor and overhead, contract services, parts and supplies, and other administrative costs. Plant operations costs were higher in the third quarter ended September 30, 2001 than costs for the same period in 2000 due to higher maintenance expenses from planned outages. Our planned maintenance expense will vary based on a number of factors including timing of our maintenance on major pieces of equipment including the boiler and turbine on each unit (generally planned for three-year and six-year cycles). Our expenditures for maintenance of major pieces of equipment are expected to be similar during the next several years.

Depreciation increased $0.2 million and $1.6 million in the third quarter and nine months ended September 30, 2001, respectively, compared to the same periods in 2000. Depreciation expense primarily relates to the acquisition of the Homer City facilities, which are being depreciated over 39 years from the date of acquisition.

Administrative and general expenses were $0.6 million and $1.5 million in the third quarter and nine months ended September 30, 2001, respectively, compared to $0.2 million and $(0.8) million for the same periods in 2000. During the nine months ended September 30, 2000, we reduced our accrual for Pennsylvania state capital tax.

Interest and other income (expense) decreased $0.2 million and $2.7 million for the third quarter and nine months ended September 30, 2001, respectively, compared to the same periods in 2000. During the nine months ended September 30, 2001, the decrease was primarily due to expenses related to removal of equipment in connection with the completion of our capital improvement program.

The effective income tax rate in the first nine months of 2001 was 43% compared to a rate of 44% for the same period in 2000. The effective tax rates are higher than the federal statutory rate of 35% due to state income taxes.

At September 30, 2001, we had cash and cash equivalents of $147.8 million. We may use amounts available under our $50 million five-year revolving credit facility for general working capital purposes. All outstanding amounts under the $50 million five-year revolving credit facility will be repaid each year on the anniversary of the issuance of the $300 million aggregate principal amount of Series A senior secured bonds and $530 million aggregate principal amount of Series B senior secured bonds

that were issued on May 27, 1999. For the third quarter ended September 30, 2001, there were no outstanding amounts under the $50 million five-year revolving credit facility. The cash and cash equivalents balance at September 30 is normally higher than December 31 due to the seasonal nature of our business and timing of interest payments on the senior secured bonds.

Net cash flow provided by operating activities totaled $178.3 million during the nine months ended September 30, 2001, compared to $106.3 million for the corresponding period in 2000. The increase of $72 million is a result of the increase in net income and the decrease in receivables from our marketing affiliate.

Net cash provided by financing activities decreased to $24.4 million for the nine months ended September 30, 2001, compared to $72.3 million for the nine months ended September 30, 2000. The decrease is primarily due to dividends of $43.6 million paid to Edison Mission Energy, our parent company, for the nine-month period ended September 30, 2001, compared to dividends of $10.1 million for the nine-month period ended September 30, 2000.

Capital expenditures for the nine months ended September 30, 2001 were $74.0 million, primarily related to the flue gas desulfurization system on Unit 3 and the selective catalytic reduction systems. The environmental improvements will enhance the economics of the Homer City units by reducing fuel costs, nitrogen oxide allowance purchases and sulfur dioxide allowance purchases. These improvements are scheduled to be completed in 2002. We expect to spend approximately $19 million for the final quarter of 2001 on capital expenditures to the Homer City facility, including environmental expenditures disclosed under "—Environmental Matters and Regulations." Our future capital expenditures will be funded through cash on hand and cash flow generated from operations.

Our principal source of liquidity is cash on hand and future cash flow from operations from EME Homer City. In addition, as mentioned above, we have a $50 million working capital facility that was fully available at September 30, 2001. The covenants contained in the senior secured bonds, which are guaranteed jointly and severally by each of our subsidiaries, restrict our ability to incur indebtedness other than subordinated indebtedness or other specified types of indebtedness not to exceed $15 million. We believe, based on our historical experience and projected cash flow from operations under current market conditions (see discussion of Market Risks Exposures below), that we will have adequate liquidity to meet our obligations as they become due in the next twelve months and over the period of the senior secured bonds. However, conditions may change, including items that are beyond our control, which could result in a shortfall of cash available to pay our debt service on the senior secured bonds. Furthermore, covenants under the senior secured bonds would limit our ability to secure additional indebtedness to provide liquidity in such circumstance.

We provide credit support for an affiliate that enters into various electric energy transactions, including futures and swap agreements. At September 30, 2001, we provided guarantees totaling $177.4 million as credit support for financial and energy contracts entered into by affiliates. These guarantees provide that we will perform the obligations of the affiliates in the event of nonperformance by them. We could be exposed to the risk of higher electric energy prices in the event of nonperformance by a counterparty. However, we do not anticipate nonperformance by a counterparty nor the marketing affiliate.

Our parent, Edison Mission Energy, has issued a Credit Support Guarantee, under which it must make up to $42 million in payments under specified conditions. The Credit Support Guarantee is available until December 31, 2001 as additional cash flow to supplement any shortfalls in cash from operations that may be used to pay our debt service obligations on the senior secured bonds and our other senior secured debt. We have an obligation under our bond financing to maintain a debt service reserve equal to the projected amount of debt service due in the next three months, which can be

satisfied through cash, a letter of credit or a parent company guaranty. At September 30, 2001, we have provided a $35 million letter of credit to satisfy our debt service reserve obligation. We also have an obligation under our bank financing to have a debt service reserve account balance in an amount equal to six months of debt service that can be satisfied through cash, a letter of credit or a parent company guaranty. Edison Mission Energy has provided a $9 million guarantee to the lenders to support this obligation.

We have initiated a consent solicitation to the holders of our $830 million senior secured bonds to amend and waive several provisions of the indenture and other security agreements in connection with the senior secured bonds, to effectuate a sale-leaseback transaction of our three coal-fired electric generating units and related facilities, owned by our indirect wholly-owned subsidiary, EME Homer City Generation L.P. The proceeds from this transaction would be used to repay and retire any outstanding indebtedness on our floating rate senior secured bank debt, of which $250 million is outstanding at September 30, 2001. Net proceeds in excess of the senior secured bank debt and cash retained in a rent reserve account will be paid to Edison Mission Energy as a dividend. There is no assurance that we will be able to obtain the necessary consents or consummate a sale-leaseback transaction on favorable terms.

Our primary market risk exposures arise from changes in electricity pool pricing and interest rates. We manage these risks by using derivative financial instruments in accordance with established policies and procedures.

With the exception of revenue generated by the Pennsylvania Electric Company Transition Contract, which expired in May 2001, and the New York State Electric & Gas Transition Contract, which expires in December 2002, and from bilateral contracts for the sale of electricity with third-party load serving entities and power marketers, our revenues and results of operations are dependent upon prevailing market prices for energy, capacity, 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:

exist which allow for monitoring of all commitments and positions with daily reporting to senior management. Our marketing affiliate performs a "value at risk" analysis in our daily business to measure, monitor and control our overall market risk exposure. The use of value at risk allows management to aggregate overall risk, compare risk on a consistent basis and identify the drivers of the risk. Value at risk measures the worst expected loss over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a single risk measurement tool, our marketing affiliate supplements this approach with industry "best practice" techniques, including the use of stress testing and worst-case scenario analysis, as well as stop limits and counterparty credit exposure limits.

We have mitigated the risk of interest rate fluctuations by arranging for fixed rate financing for the majority of our project financings. Interest rate changes affect the borrowings under our working capital and capital improvement credit facilities that are utilized to fund cash needs of the Homer City facilities. We do not believe that interest rate fluctuations will have a materially adverse effect on our financial position or results of operations.

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 operations. 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.

The Pennsylvania Department of Environmental Protection (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 has 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.

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 anticipate upgrades to the environmental controls at the Homer City plant to reduce sulfur dioxide and nitrogen oxide emissions to result in expenditures of approximately $15 million for the fourth quarter of 2001 and $12 million in 2002.

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" 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 new source review 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. 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.

additional pollution control requirements, fines or penalties at this time. In May 2001, President Bush issued a directive for a 90-day review of new source review "interpretation and implementation" by the Administrator of the Environmental Protection Agency and the Secretary of the U.S. Department of Energy, which has been extended indefinitely. President Bush also directed the Attorney General to review ongoing new source review legal actions to "ensure" they are "consistent with the Clean Air Act and its regulations." Both actions were recommendations detailed within the Bush administration's "National Energy Policy Task Force Report."

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)(l) 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)(l). 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.

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.

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, these regulations must be adopted by November 9, 2001. The consent decree also requires the agency to propose similar regulations for existing facilities by February 28, 2002, and 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.

The Comprehensive Environmental Response, Compensation, and Liability Act, which is also known as CERCLA, and similar state statutes, require the cleanup of sites from which there has been a release or threatened release of hazardous substances. As of the date of this report, we are unaware of any material liabilities under CERCLA or similar state statutes; however, we cannot assure you that we will not incur CERCLA liability or similar state law liability in the future.

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, and 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.

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 their operations.

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 impact of this new accounting standard and are unable to predict at this time the impact on our consolidated financial statements.

For a complete discussion of market risk sensitive instruments, refer to "Market Risk Exposures" in Item 7. of Edison Mission Holdings Co.'s Annual Report on Form 10-K for the fiscal year ended December 31, 2000. Management believes that at September 30, 2001, there has been no material change to this information.

The financial statements of Chestnut Ridge Energy Co. are provided under Rule 3-10 of Regulation S-X as the shares of Chestnut Ridge Energy Co. represent a substantial portion of the collateral for Edison Mission Holdings Co.'s $830 million senior secured bonds. In addition, Chestnut Ridge Energy Co. has unconditionally guaranteed the $830 million senior secured bonds of Edison Mission Holdings Co.

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

CHESTNUT RIDGE ENERGY CO.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)

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

We have made all adjustments, including recurring accruals, that are necessary to present fairly the financial position and results of operations for the periods covered by this report. The results of operations for the nine months ended September 30, 2001 are not necessarily indicative of the operating results for the full year.

The Company's significant accounting policies are described in Note 2 to its Financial Statements as of December 31, 2000, included in Edison Mission Holdings Co.'s 2000 Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 2, 2001. The Company follows the same accounting policies for interim reporting purposes, with the exception of the change in accounting for derivatives (see Note 3). This quarterly report should be read in connection with such financial statements.

The Company owns a 99 percent limited partnership interest in EME Homer City Generation L.P. As a limited partner, the Company does not have a controlling financial interest in EME Homer City, and, in accordance with the provisions of the Accounting Principles Board Opinion No. 18, the Company accounts for its investment in EME Homer City under the equity method. Accordingly, the investment in EME Homer City was recorded at cost with adjustments made to the carrying amount of the investment to recognize the Company's share of the earnings, losses or distributions of EME Homer City after the date of the investment. The following table presents summarized financial information for EME Homer City for the quarters and nine months ended September 30, 2001 and 2000.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2001		2000		2001		2000
	(Unaudited)				(Unaudited)
Operating revenues	$	153,985	$	131,049	$	388,197	$	331,677
Operating income		74,237		57,118		161,489		112,362
Net income		24,850		13,573		34,774		4,840

Effective January 1, 2001, the Company and its investee, EME Homer City 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, EME Homer City recorded all derivatives at fair value unless the derivatives qualified for the normal sales and purchases exception. EME Homer City's physical fuel contracts qualified under this exception. EME Homer City did not use this exception for 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 from EME Homer City 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 Company recorded a $61.2 million, after tax, unrealized holding loss upon adoption of this change in accounting principle from its share of the unrealized holding loss from EME Homer City and the impact of deferred Pennsylvania state taxes, which is reflected in accumulated other comprehensive income in the balance sheet. EME Homer City recorded a net loss of $482,000 from the ineffective portion of its cash flow hedges during the three months ended September 30, 2001. Our share of the loss of $477,000 is reflected in equity in income from EME Homer City in the statement of operations.

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, EME Homer City qualified to use the normal sales and purchases exception for their forward sales contracts commencing July 1, 2001. Based on this accounting guidance, on July 1, 2001, EME Homer City eliminated the value of its forward sale contracts from its balance sheet. Our share of the cumulative effect of this change in accounting is reflected as a $15.4 million decrease in other comprehensive income.

	Nine Months Ended September 30,
	2001		2000
	(Unaudited)
Cash paid for interest	$	—	$	—
Cash paid for income taxes		—		—

The financial statements of EME Homer City Generation L.P., the Partnership, are provided under Rule 3-10 of Regulation S-X as the partnership interests of EME Homer City Generation L.P. represent a substantial portion of the collateral for Edison Mission Holdings Co.'s $830 million senior secured bonds. In addition, EME Homer City Generation L.P. has unconditionally guaranteed the $830 million senior secured bonds of Edison Mission Holdings Co.

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

EME HOMER CITY GENERATION L.P.
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)

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

EME HOMER CITY GENERATION L.P.
NOTES TO FINANCIAL STATEMENTS
(Dollars in thousands)

The Partnership's significant accounting policies are described in Note 2 to its Financial Statements as of December 31, 2000, included in Edison Mission Holdings Co.'s 2000 Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 2, 2001. The Partnership follows the same accounting policies for interim reporting purposes, with the exception of the change in accounting for derivatives (see Note 2). This quarterly report should be read in connection with such financial statements.

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

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's physical fuel contracts qualified under this exception. 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. The Partnership recorded a net loss of $482,000 from the ineffective portion of cash flow hedges during the three months ended September 30, 2001. The loss is reflected in income (loss) from price risk management in the statement of operations.

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 separate transition contracts with Pennsylvania Electric Company (Penelec) and New York State Electric & Gas Corporation (NYSEG), under which it may exercise a put option to sell certain quantities of capacity to Penelec and NYSEG, and Penelec and NYSEG may exercise call options to purchase certain quantities of capacity. The terms of the NYSEG Transition Contract continue until December 31, 2002 and the Penelec Transition Contract expired on May 31, 2001. The Partnership exercised its put options to sell 942 MW of capacity to Penelec for the full period from March 18, 1999 through May 31, 2001 under the Penelec Transition Contract for a price of $49.90/MW-day from March 18, 1999 through May 31, 1999, $59.90/MW-day through May 31, 2000, and $77.40/MW-day through May 31, 2001. The Partnership has amended the NYSEG Transition Contract and sold 500 MW of capacity to NYSEG through May 31, 2000 for a price of $60.00/MW-day, 370 MW of capacity through September 30, 2000 for $72.17/MW-day, and plans to sell 430 MW of capacity through December 31, 2001 for $72.17/MW-day, 400 MW through April 30, 2002 for $51.00/MW-day and 300 MW through December 31, 2002 for $99.84/MW-day.

Pennsylvania Department of Environmental Protection (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 Homer City facilities' ash disposal site has not shown any signs that would require abatement. Management does not believe that the costs of maintaining and, if necessary, 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. There is no assurance 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. 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. In May 2001, President Bush issued a directive for a 90-day review of new source review "interpretation and implementation" by the Administrator of the Environmental Protection Agency and the Secretary of the U.S. Department of Energy, which has been extended indefinitely. President Bush also directed the Attorney General to review ongoing new source review legal actions to "ensure" they are "consistent with the Clean Air Act and its regulations." Both actions were recommendations detailed within the Bush administration's "National Energy Policy Task Force Report."

In connection with the Partnership's purchase of the Homer City facilities on March 18, 1999, 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 filed for bankruptcy, however, it operated the collection and treatment system until May 1999 when 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 has 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 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 Blacklick Creek Watershed Association to develop and operate a collection and treatment system for the Penn Hill No. 2 discharge. The Watershed Association has started construction on the Penn Hill No. 2 system and expects it to be completed in November 2001.

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% after the Penn Hill No. 2 system construction is completed. 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.

Upon acquisition of the Homer City facilities, the Partnership began major plant improvements consisting primarily of a turnkey pollution control retrofit project. The estimated cost of this project is $270 million, of which $243 million has been incurred prior to September 30, 2001. We expect to spend approximately $15 million for the remainder of 2001 and $12 million in 2002 to complete this project.

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 $0.20 to $0.35 per ton of coal processed, depending on the level of tonnage.

The Partnership has entered into Interconnection Agreements with NYSEG and Penelec to provide interconnection services necessary to interconnect the Homer City Station with NYSEG's and Penelec's transmission systems. Unless an Interconnection Agreement is terminated earlier in accordance with its terms, it will terminate on a date mutually agreed to by the Partnership, 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 to modifications, additions, upgrades or repowering of the Homer City units. The Partnership is required to compensate NYSEG and Penelec for all reasonable costs associated with any modifications, additions or replacements made to NYSEG's or Penelec's interconnection facilities or transmission systems in connection with any modification, addition or upgrade to the Homer City units.

	Nine Months Ended September 30,
	2001		2000
	(Unaudited)
Cash paid for interest	$	78,968	$	55,130
Cash paid for income taxes		—		—

MANAGEMENT'S DISCUSSION AND ANALYSIS
OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

We are a Pennsylvania limited partnership which is a partnership among Chestnut Ridge Energy Company, as a limited partner with a 99% interest, and Mission Energy Westside Inc., as a general partner with a 1% interest. Both Chestnut Ridge Energy and Mission Energy Westside are wholly-owned subsidiaries of Edison Mission Holdings, which is a wholly-owned subsidiary of Edison Mission Energy. We were formed on October 31, 1998 for the purpose of acquiring, owning and operating the facilities. Although we were formed on October 31, 1998, we had no significant activity before the acquisition of the facilities.

On March 18, 1999, we completed the acquisition of the facilities and assumed specified liabilities of the former owners. The 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. We benefit from direct transmission access into both the Pennsylvania-New Jersey-Maryland power market (PJM) and the New York independent system operator (NYISO). The acquisition was financed through a capital contribution of $273 million from our partners and a loan from our affiliate, Edison Mission Finance Co.

We derive revenue from the sale of energy and capacity into PJM and NYISO and from bilateral contracts with power marketers and load serving entities within PJM, NYISO and the surrounding markets. We have entered into a hedging contract with a marketing affiliate, which was formed by Edison Mission Energy on November 20, 1998, for the sale of energy and capacity produced by the facilities, which enables this marketing affiliate to engage in forward sales and hedging. Under this hedging contract, we pay the marketing affiliate fees of $0.02/MWh plus emission allowance fees. The net fees earned by the marketing affiliate were $0.1 million and $0.7 million for the third quarter and nine months ended September 30, 2001, respectively, compared to $0.2 million and $1.5 million in the corresponding periods in 2000.

During 2001, we entered into three transactions for unforced capacity with our marketing affiliate as follows: 450 MW for the period of June-December 2001, 150 MW for the period of January-December 2002, and 125 MW for the period January-May 2002. Each was at fair market value for such unforced capacity at the time. Total payments for the three transactions will amount to approximately $25.5 million.

Mission Energy 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, Edison International bills Edison Mission Energy for any direct labor and out-of-pocket expenses for services directly requested for our benefit. We believe the allocation methodologies are reasonable.

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

Operating expenses increased $5.8 million and $7.4 million for the third quarter and nine months ended September 30, 2001, respectively, compared to the corresponding periods in 2000. Operating expenses consisted of expenses for fuel, plant operations, depreciation, and administrative and general expenses. The change in components of operating expenses is discussed below.

Fuel costs increased $1.4 million for the third quarter ended September 30, 2001, compared to the corresponding period in 2000. Fuel costs increased $3.3 million for the nine months ended September 30, 2001, compared to the same period in 2000. The change in fuel costs is due to increased production offset by lower average fuel prices. The average price of coal per ton was $27.24 for the nine months ended September 30, 2001, compared to $28.64 for the same period in 2000. The average price decreased due to changes in the type of coal used in operations. The 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 is supplied under existing contracts with regional mines that are located within approximately 100 miles of the facilities, while the remainder is purchased on the spot market. The coal for these units that is purchased from local mines is cleaned by the coal-cleaning facility to reduce sulfur and ash content. Unit 3 currently utilizes lower sulfur coal that is blended at an on-site coal blending facility. As we complete the Environmental Improvements, we plan to eliminate the lower sulfur coal at Unit 3 (as our sulfur emissions will be reduced through use of the Environmental Improvements) that will reduce our fuel costs. The lower fuel costs will be partially offset by higher depreciation expense from the Environmental Improvements and interest expense (currently being capitalized).

Administrative and general expenses were $0.2 million in the third quarter ended September 30, 2001. There were no comparable expenses in the same period in 2000. Administrative and general expenses were $0.2 million and $(1.9) million for the nine months ended September 30, 2001 and September 30, 2000, respectively. During the nine months ended September 30, 2000, we reduced our accrual for Pennsylvania state capital tax.

The effective income tax rate in the first nine months of 2001 was 40% compared to a rate of 49% for the same period in 2000. The effective tax rates are higher than the federal statutory rate of 35% due to state income taxes.

At September 30, 2001, we had cash and cash equivalents of $147.8 million. The cash and cash equivalents balance at September 30 is normally higher than December 31 due to the seasonal nature of our business and the timing of interest payments on the senior secured bonds.

Net cash flow provided by operating activities totaled $146.0 million during the nine months ended September 30, 2001, compared to $95.5 million for the corresponding period in 2000. The increase of $50.5 million is a result of the increase in net income and the decrease in receivables from our marketing affiliate.

Net cash provided by financing activities decreased to $56.6 million for the nine months ended September 30, 2001, compared to $83.1 million for the nine months ended September 30, 2000. The decrease is due to a decrease in borrowings and an increase in repayments of debt obligations.

Capital expenditures for the nine months ended September 30, 2001 were $74.0 million, primarily related to the flue gas desulfurization system on Unit 3 and the selective catalytic reduction systems. The environmental improvements will enhance the economics of the Homer City units by reducing fuel costs, nitrogen oxide allowance purchases and sulfur dioxide allowance purchases. These improvements are scheduled to be installed in 2002. We expect to spend approximately $19 million for the final quarter of 2001 on capital expenditures to the Homer City facility, including environmental expenditures disclosed under "—Environmental Matters and Regulations." Our future capital expenditures will be funded through cash on hand and cash flow generated from operations.

Our principal source of liquidity is cash on hand and future cash flow from operations. In addition, we have access to a $50 million working capital facility that was fully available at September 30, 2001. The covenants contained in the senior secured bonds, which we have guaranteed, restrict our ability to incur indebtedness other than subordinated indebtedness or other specified types of indebtedness not to exceed $15 million. We believe, based on our historical experience and projected cash flow from operations under current market conditions (see discussion of Market Risks Exposures below), that we will have adequate liquidity to meet our obligations as they become due in the next twelve months and over the period of the senior secured bonds. However, conditions may change, including items that are beyond our control, which could result in a shortfall of cash available to meet payments due under our subordinated loan, which are indirectly used to pay debt service on the senior secured bonds. Furthermore, covenants under the senior secured bonds would limit our ability to secure additional indebtedness to provide liquidity in such circumstance.

Our indirect parent, Edison Mission Holdings, provides credit support for an affiliate that enters into various electric energy transactions, including futures and swap agreements. At September 30, 2001, Edison Mission Holdings provided guarantees totaling $177.4 million as credit support for financial and energy contracts entered into by affiliates. These guarantees provide that Edison Mission Holdings will perform the obligations of the affiliates in the event of nonperformance by them. Edison Mission Holdings could be exposed to the risk of higher electric energy prices in the event of nonperformance by a counterparty. However, Edison Mission Holdings does not anticipate nonperformance by a counterparty nor the marketing affiliate.

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

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.

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. In May 2001, President Bush issued a directive for a 90-day review of new source review "interpretation and implementation" by the Administrator of the Environmental Protection Agency and the Secretary of the U.S. Department of Energy, which has been extended indefinitely. President Bush also directed the Attorney General to review ongoing new source review legal actions to "ensure" they are "consistent with the Clean Air Act and its regulations." Both actions were recommendations detailed within the Bush administration's "National Energy Policy Task Force Report."

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.

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, we recorded all derivatives at fair value unless the derivatives qualified for the normal sales and purchases exception. Our physical fuel contracts qualified under this exception. We did not use this exception for our forward sales contracts due to the net settlement procedures used by our marketing affiliate with counterparties for the period between January 1, 2001 through June 30, 2001. For the period between January 1, 2001 through June 30, 2001, our forward sales contracts qualified for treatment under SFAS No. 133 as cash flow hedges with appropriate adjustments made to other comprehensive income. 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. We recorded a $69.3 million, after tax, unrealized holding loss upon adoption of this change in accounting principle reflected in accumulated other comprehensive income in the consolidated balance sheet. We recorded a net loss of $482,000 from the ineffective portion of cash flow hedges during the three months ended September 30, 2001. The loss is reflected in income (loss) from price risk management in the consolidated statement of operations.

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, we qualified to use the normal sales and purchases exception for our forward sales contracts commencing July 1, 2001. Based on this accounting guidance, on July 1, 2001, we eliminated the value of our forward sale contracts from our balance sheet. The cumulative effect of this change in accounting is reflected as a $17.4 million decrease in other comprehensive income.

The financial statements of Edison Mission Finance Co. are provided under Rule 3-10 of Regulation S-X as the shares of Edison Mission Finance Co. represent a substantial portion of the collateral for Edison Mission Holdings Co.'s $830 million senior secured bonds. In addition, Edison Mission Finance Co. has unconditionally guaranteed the $830 million senior secured bonds of Edison Mission Holdings Co.

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

The Company's significant accounting policies are described in Note 2 to its Financial Statements as of December 31, 2000, included in Edison Mission Holdings Co.'s 2000 Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 2, 2001. The Company follows the same accounting policies for interim reporting purposes. This quarterly report should be read in connection with such financial statements.

	Nine Months Ended September 30,
	2001		2000
	(Unaudited)
Cash paid for interest	$	45,289	$	6,114
Cash paid for income taxes		—		—

EME Homer City Generation L.P. filed the following report on Form 8-K during the quarter ended September 30, 2001.

Date of Report		Date Filed		Item(s) Reported
September 24, 2001		September 24, 2001		5, 7

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

California (State or other jurisdiction of incorporation or organization)		33-0826940 (I.R.S. Employer Identification No.)
18101 Von Karman Avenue, Suite 1700 Irvine, California (Address of principal executive offices)		92612 (Zip Code)

Name and Number	State of Incorporation or Organization	Primary Standard Industrial Classification Code Number	I.R.S. Employer Identification
Edison Mission Finance Co.	California	4991	33-0839202
18101 Von Karman Avenue, Suite 1700 Irvine, California 949-752-5588
Homer City Property Holdings, Inc.	California	4991	33-0851685
18101 Von Karman Avenue, Suite 1700 Irvine, California 949-752-5588
Mission Energy Westside, Inc.	California	4991	33-0550657
18101 Von Karman Avenue, Suite 1700 Irvine, California 949-752-5588
Chestnut Ridge Energy Company	California	4991	33-0826590
18101 Von Karman Avenue, Suite 1700 Irvine, California 949-752-5588
EME Homer City Generation L.P.	Pennsylvania	4991	33-0826938
1750 Power Plant Road Homer City, Pennsylvania 724-479-9011

			September 30, 2001		December 31, 2000
			(Unaudited)
Assets
Current Assets
	Cash and cash equivalents		$	147,752	$	19,125
	Due from affiliates			46,909		84,166
	Fuel inventory			14,652		14,993
	Spare parts inventory			22,157		23,582
	Assets under price risk management			2,705		—
	Other current assets			5,590		2,758

		Total current assets		239,765		144,624

Property, Plant and Equipment				2,116,670		2,040,564
	Less accumulated depreciation			120,976		84,280

		Net property, plant and equipment		1,995,694		1,956,284

Other Assets
	Deferred financing charges, net			10,727		11,291

Total Assets			$	2,246,186	$	2,112,199

Liabilities and Shareholder's Equity
Current Liabilities
	Accounts payable		$	4,136	$	16,479
	Accrued liabilities			29,726		32,200
	Interest payable			36,861		19,459
	Liabilities under price risk management			3,364		—
	Other current liabilities			—		469

		Total current liabilities		74,087		68,607

Long-Term Debt				1,080,000		1,012,000
Deferred Taxes				106,501		62,074
Benefit Plans				17,625		17,625

Total Liabilities				1,278,213		1,160,306

Commitments and Contingencies (Note 3)
Shareholder's Equity
	Common stock, no par value; 10,000 shares authorized; 100 shares issued and outstanding			—		—
	Additional paid-in capital			910,456		925,609
	Retained earnings			57,517		26,284
	Accumulated other comprehensive income			—		—

Total Shareholder's Equity				967,973		951,893

Total Liabilities and Shareholder's Equity			$	2,246,186	$	2,112,199

			Three Months Ended September 30,						Nine Months Ended September 30,
			2001			2000			2001			2000
			(Unaudited)						(Unaudited)
Operating Revenues from Marketing Affiliate
	Capacity revenues		$	23,386		$	14,906		$	50,964		$	36,735
	Energy revenues			131,618			111,409			338,221			290,208
	Income (loss) from price risk management			(1,019	)		4,734			(988	)		4,734

		Total operating revenues		153,985			131,049			388,197			331,677

Operating Expenses
	Fuel			48,872			47,430			128,353			125,015
	Plant operations			18,164			14,125			61,237			60,852
	Depreciation			12,530			12,377			36,938			35,379
	Administrative and general			627			244			1,468			(801	)

		Total operating expenses		80,193			74,176			227,996			220,445

Operating Income				73,792			56,873			160,201			111,232

Other Income (Expense)
	Interest and other income (expense)			544			732			(526	)		2,166
	Loss on disposal of assets			—			(760	)		(861	)		(760	)
	Interest expense			(18,155	)		(18,563	)		(54,664	)		(56,418	)

		Total other income (expense)		(17,611	)		(18,591	)		(56,051	)		(55,012	)

Income before income taxes				56,181			38,282			104,150			56,220
Provision for income taxes				24,423			15,754			44,426			24,827

Net Income			$	31,758		$	22,528		$	59,724		$	31,393

			Three Months Ended September 30,					Nine Months Ended September 30,
			2001			2000		2001			2000
			(Unaudited)					(Unaudited)
Net Income			$	31,758		$	22,528	$	59,724		$	31,393
Other comprehensive expense, net of tax:
	Unrealized gains (losses) on derivatives qualified as cash flow hedges:
		Cumulative effect of change in accounting for derivatives, net of income tax benefit of $13,566 and $67,647 for the three months and nine months ended September 30, 2001, respectively		(15,506	)		—		(77,317	)		—
		Other unrealized holding gains arising during period, net of income tax expense of $54,187 for the nine months ended September 30, 2001		—			—		61,933			—
		Reclassification adjustment for losses included in net income, net of income tax benefit of $13,460 for the nine months ended September 30, 2001		—			—		15,384			—

Comprehensive Income			$	16,252		$	22,528	$	59,724		$	31,393

			Chestnut Ridge Energy Company			Mission Energy Westside Inc.			Total Partners' Equity
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			34,426			348			34,774
	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 September 30, 2001 (unaudited)			$	229,272		$	2,317		$	231,589