MIDWEST GENERATION LLC - 10-K Annual Report

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

Midwest Generation, LLC
(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)		33-0868558 (I.R.S. Employer Identification No.)
One Financial Place 440 South LaSalle Street, Suite 3500 Chicago, Illinois (Address of principal executive offices)		60605 (Zip Code)

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

8.30% Series A Pass-Through Certificates due 2009
8.56% Series B Pass-Through Certificates due 2016
(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 units outstanding of the registrant's Membership Interests as of March 28, 2002: 100 units (all units held by an affiliate of the registrant).

Item		Page
PART I
1.	Business	1
2.	Properties	18
3.	Legal Proceedings	19
4.	Submission of Matters to a Vote of Security Holders	19
PART II
5.	Market for Registrant's Common Equity and Related Stockholder Matters	20
6.	Selected Financial Data	21
7.	Management's Discussion and Analysis of Results of Operations and Financial Condition	22
7a.	Quantitative and Qualitative Disclosures about Market Risk	38
8.	Financial Statements and Supplementary Data	39
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	39
PART III
10.	Managers and Executive Officers of the Registrant	67
11.	Executive Compensation	68
12.	Security Ownership of Certain Beneficial Owners and Management	68
13.	Certain Relationships and Related Transactions	68
PART IV
14.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	69
	Signatures	78

We were formed on July 12, 1999 as a special-purpose Delaware limited liability company with Edison Mission Midwest Holdings, which we refer to as Midwest Holdings, as the sole owner. Midwest Holdings is a wholly-owned subsidiary of Midwest Generation EME, LLC, which is in turn a wholly-owned subsidiary of Edison Mission Energy. We were formed for the purpose of owning or leasing, making improvements to and operating the power generation assets we purchased from Commonwealth Edison. We acquired these power generation assets on December 15, 1999 for a purchase price of approximately $4.9 billion, with adjustments for changes in the book value of inventories and pro-rations related to specific items, including but not limited to taxes, rents and fees. Prior to the acquisition of these power generation assets, we had no significant business activity.

Concurrent with the acquisition, we assigned our right to purchase the Collins Station, a 2,698 megawatt (MW) gas and oil-fired generating station located in Illinois, to four third-party entities. After this assignment, and the purchase of the facility by the third parties, an affiliate of ours leased and we subleased the Collins Station. Each of the leases and subleases has an initial term of 33.75 years. These subleases have been accounted for as a lease financing for accounting purposes.

The aggregate megawatts we currently own or lease as a result of the acquisition is approximately 9,539 MW and consist of the following:

In connection with the acquisition of these power generation assets, we entered into three five-year power purchase agreements for the coal-fired stations, the Collins Station and the peaker stations with Commonwealth Edison. Subsequently, Commonwealth Edison assigned its rights and obligations under these power purchase agreements to Exelon Generation. We currently derive a substantial majority of our revenue from the sale of energy and capacity to Exelon Generation under these power purchase agreements. We have entered into a contract with a marketing affiliate for scheduling and related services and to market energy that is permitted to be sold under the power purchase agreements and to engage in hedging activities. The marketing affiliate also purchases fuel, other than coal, and enters into fuel hedging arrangements on our behalf.

In August 2000, we completed a sale-leaseback transaction with respect to the Powerton and Joliet power facilities to third-party lessors for an aggregate purchase price of $1.367 billion. In connection with this transaction, we facilitated the issuance of $333.5 million 8.30% Series A Pass-Through Certificates and $813.5 million 8.56% Series B Pass-Through Certificates through a private placement. In 2001, these certificates were subsequently exchanged for certificates that were registered with the Securities and Exchange Commission, and identical in all material respects to the privately held certificates, pursuant to an exchange offer.

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 Forms 10-K for the year ended December 31, 2001.

Our principal executive offices are located at One Financial Place, 440 South LaSalle Street, Suite 3500, Chicago, Illinois 60605, and our telephone number is (312) 583-6000.

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.

Until the enactment of the Public Utility Regulatory Policies Act of 1978, utilities were the only producers of bulk electric power intended for sale to third parties in the United States. The Public Utility Regulatory Policies Act encouraged the development of independent power by removing regulatory constraints relating to the production and sale of electric energy by certain non-utilities and requiring electric utilities to buy electricity from certain types of non-utility power producers, qualifying facilities, under certain conditions. The passage of the Energy Policy Act of 1992 further encouraged the development of independent power by significantly expanding the options available to independent power producers with respect to their regulatory status and by liberalizing transmission access. As a result, a significant market for electric power produced by independent power producers, such as us, has developed in the United States since the enactment of the Public Utility Regulatory Policies Act. In 1998, utility deregulation in several states led utilities to divest generating assets, which has created new opportunities for growth of independent power in the United States. In deregulating markets, industry

trends and regulatory initiatives have transformed vertically integrated, price regulated utilities, into markets in which generators complete with each other for their principal customers (whole power suppliers, distributions companies, and major end-users) on the basis of price, reliability and other factors. As a result of the recent energy crises in California, some states have either discontinued or delayed implementation of initiatives involving retail deregulation. These developments have generally not affected the market structures in Illinois, where our power plants are located.

The Collins Station is a 2,698 megawatt net gas and oil-fired power plant located in Grundy County, near Morris, Illinois. The plant was built in 1977 and occupies approximately 3,723 acres, inclusive of Heideke Lake, the station's cooling lake. Collins Station contains five dual-fueled steam generators originally fired using No. 6 heavy fuel oil, but now capable of burning natural gas or oil. This dual fuel capacity gives Collins Station flexibility to switch between natural gas and oil based on economics.

Natural gas is procured in the monthly and daily spot markets, shipped at the seller's risk to Chicago, and then delivered to Collins Station by Nicor Gas Company under a delivery contract that runs through 2003. Nicor Gas Company manages storage inventory and purchases gas for us under an agency agreement that runs concurrently with the delivery contract.

The Crawford Station is a 542 megawatt net coal-fired power plant located in Cook County, Illinois, and is within the city limits of Chicago. The original plant was built in 1925 and occupies approximately 72 acres, inclusive of the switchyard. The original generating units have been retired. Units 7 and 8 began operations in 1958 and 1961, respectively.

Coal is delivered by barge, which is moved via the Chicago Sanitary and Ship Canal to Crawford Station. The barge towing company delivers three to four barges daily and removes empty barges. Coal from the barges is unloaded directly to the bunkers or to ground storage. Coal for the Crawford Station is loaded into barges at the Will County Station. Crawford Station receives a blend of Decker and southern Powder River Basin coal, although it can burn several Powder River Basin coals as long as sodium in the ash is sufficient to maintain precipitator performance. Natural gas is used for ignition and combustion support and for full boiler operation, if desired. Peoples Gas delivers natural gas under a delivery contract that includes balancing storage, which is also shared by Fisk Station and Commonwealth Edison's peakers located in Chicago.

The Fisk Station is a 327 megawatt net coal-fired power plant located in Cook County, Illinois, and is within the city limits of Chicago. The original plant was built in 1903 and occupies approximately 44 acres, inclusive of the switchyard. The original generating units have been retired. Unit 19 began operations in 1959.

Coal is delivered by barge, which is moved via the Chicago Sanitary and Ship Canal to Fisk Station. The barge towing company delivers two to three barges daily and removes empty barges. Coal from the barges is unloaded directly to the bunkers. Fisk Station has no ground storage and receives its coal on a "just in time" basis. Coal for Fisk Station is loaded into barges at the Will County Station. There are no intervening locks to prevent the timely delivery of coal. Fisk Station receives a blend of Decker and southern Powder River Basin coal, although it can burn several Powder River Basin coals as long as sodium in the ash is sufficient for improved precipitator performance. Natural gas is used for

ignition and combustion support and for full boiler operation, if desired. Peoples Gas delivers natural gas under a delivery contract that includes balancing storage, which is also shared by the Crawford Station.

The Joliet Station is located in Joliet, Illinois approximately 40 miles southwest of Chicago on a combined approximately 467 acre site on the Des Plaines River near Interstate 80. The original Joliet facility was constructed in 1917. The remaining operating generating units are Units 6, 7 and 8, as the other generating units have been retired. Only Units 7 and 8 are subject to the leveraged lease transactions described in this annual report. The operation of Units 7 and 8 started in 1965 and 1966, respectively.

Joliet Unit 6 is a 314 megawatt net coal-fired unit located adjacent to, but across the river from, Joliet Units 7 and 8, in Will County, Illinois. Joliet Units 7 and 8, which are also coal-fired, have a combined capacity of 1,044 megawatts net. The original generating units have been retired. Unit 6 began operation in 1959.

The Joliet Station is accessible by road and railroad. The railroad spur can be used for major equipment hauling and is designed for unit train coal deliveries. Natural gas is delivered for the boilers as a startup and stabilizing fuel by Nicor Gas Company under a delivery contract.

The Joliet Station receives coal by train delivered by the Chicago, Central, and Pacific Railroad Company from interchange points with the Union Pacific or Burlington Northern Santa Fe Railroads. The Joliet Station receives southern Powder River Basin coal, primarily from the Black Thunder mine, that is sodium enhanced for improved precipitator performance.

The Powerton Station is a 1,538 megawatt net coal-fired station located in Pekin, Illinois approximately 16 miles southwest of Peoria or 166 miles from Chicago on an approximately 568 acre site on the Illinois River near Illinois Route 29. The site also includes an approximately 1,440 acre lake. The original Powerton Station was constructed in 1928. The remaining operating generating units are Units 5 and 6, as the other generating units have been retired. The operation of Units 5 and 6 started in 1972 and 1975, respectively.

The Powerton Station currently receives southern Powder River Basin coal, primarily from the Rochelle mine and also from the Jacobs Ranch, Decker and Antelope mines, as well as the Black Thunder mine. With the exception of the Decker mine, which is located in Montana, all of these mines are located in Wyoming. The Powerton Station may burn coal from a variety of Powder River Basin source mines.

The Waukegan Station is a 789 megawatt net coal-fired power plant located in Waukegan, in Lake County, Illinois, on Lake Michigan. The original plant was built in 1923. The newer portion of the plant was built beginning in 1952. The plant occupies approximately 194 acres, inclusive of the switchyard. Units 6, 7 and 8 began operations in 1952, 1958 and 1962, respectively.

The Waukegan Station consists of three coal-fired generators. Unit 6 utilizes oil for ignition and startup, while Unit 7 utilizes oil or natural gas and Unit 8 utilizes natural gas for ignition and startup. The facilities receive coal by unit train delivered by the Union Pacific Railroad. The Elgin, Joliet and Eastern Railroad can also deliver to Waukegan Station from an interconnection point with the Union Pacific Railroad. Waukegan Station receives Powder River Basin coal primarily from Jacobs Ranch. This coal is sodium enhanced, if necessary, for improved precipitator performance.

The Will County Station is a 1,092 megawatt net coal-fired power plant located in Lockport, in Will County, Illinois. The station was built in 1955 and occupies approximately 215 acres, inclusive of the switchyard and other coal-fired steam generators. Units 1, 2, 3 and 4 began operations between 1955 and 1963. The units utilize oil for ignition and startup.

The Will County Station receives coal deliveries by unit train by the Elgin, Joliet & Eastern Railway Company from interchange points with the Union Pacific Railroad or the Burlington Northern Santa Fe Railroad. Will County receives Powder River Basin coal from the Decker, Rochelle and Jacobs Ranch mines. Decker coal is blended with southern Powder River Basin coal to obtain sodium levels sufficient for improved precipitator performance. Will County uses No. 2 distillate fuel oil for ignition and combustion support, which is delivered by tanker truck to a 100,000 gallon storage tank. Will County has no natural gas service.

The on-site peaking units consist of four peaking facilities: Crawford, Fisk, Waukegan and Joliet. The on-site peaking units were commissioned in 1968, except for Joliet, which was commissioned in 1969.

The off-site peaking units consist of five peaking facilities: Bloom, Calumet, Electric Junction, Lombard and Sabrooke. The off-site peaking units were commissioned in 1969, except for Electric Junction, which was commissioned in 1970.

Both the on-site peaking units and the off-site peaking units burn either No. 2 distillate oil (jet fuel) or both natural gas and No. 2 distillate oil. Natural gas is purchased in the monthly and daily spot markets and is shipped at the seller's risk to Chicago. Peoples Gas provides delivery services, including balancing storage, to the site under tariffs approved by the Illinois Commerce Commission.

We purchase No. 1 distillate oil, or jet oil, and No. 2 distillate oil from bids taken annually. Shipments to the site are in tanker trucks and inventory is replenished as needed by the site. The oil price is tied to the Oil Price Information Service posted weekly price, or market price, on the date of delivery. Truck delivery charges are at fixed agreed-upon prices.

We currently derive substantially all of our revenue from the sale of energy and capacity to Exelon Generation under power purchase agreements. Our energy and capacity that are not purchased under power purchase agreements are sold at market prices to neighboring utilities, municipalities, third-party electricity retailers, large consumers and power marketers through a marketing affiliate.

While formal market mechanisms such as independent system operators and power exchanges do not yet exist in the Mid-America Interconnected Network and the East Central Area Reliability Council, a significant bilateral trading infrastructure is already present. This infrastructure facilitates the marketing of electricity. This is a consequence of the very deep Mid-America Interconnected Network and East Central Area Reliability Council markets, as well as the already significant electricity deregulation that is occurring in states such as Illinois and Ohio. Consequently, our marketing strategy will be largely influenced by the applicable market structure that develops. We expect that the coal units will have some contracted revenues apart from the power purchase agreements. The remainder of coal-fired generation output, together with output from the Collins Station and the peaking units' output, will be sold on a spot basis.

On December 15, 1999, we entered into three separate power purchase agreements with Commonwealth Edison with terms of up to five years, and, in January 2001, Commonwealth Edison assigned these agreements to Exelon Generation. Under these agreements, we have agreed to make the capacity of the power generation stations we purchased from Commonwealth Edison available to Exelon Generation. These agreements allow us to sell any excess electric energy, including energy not dispatched by Exelon Generation, to other purchasers under specified conditions. Payments under these power purchase agreements constituted approximately 99% of our energy and capacity revenues during the years ended December 31, 2001 and 2000, with the balance coming from third-party sales of electric energy.

Exelon Corporation, Exelon Generation's parent company, is a public company and is subject to the informational requirements of the Exchange Act. Exelon Corporation's consolidated financial statements are filed with the Securities and Exchange Commission.

In connection with the acquisition of the Commonwealth Edison coal-fired stations, including the Powerton Station and the Joliet Station, we entered into a five-year power purchase agreement with Commonwealth Edison, which was subsequently assigned to Exelon Generation. The agreement expires on December 31, 2004. This agreement provides stability of cash flows to us, especially during the early years, when the majority of power is contracted.

Under this agreement, Exelon Generation purchases capacity and has the right to purchase energy generated by the coal-fired stations from us. The agreement provides for capacity and energy payments. Exelon Generation is obligated to make a capacity payment for the units under contract, providing us revenue for fixed charges such as debt service, labor and insurance, and an energy payment for the electricity produced by these units, compensating us for variable costs of production. If Exelon Generation does not fully dispatch the units under contract, we may sell the excess energy to third parties, subject to several conditions.

The agreement identifies the units that are contracted to Exelon Generation as reserved or optional capacity during its term. The power purchase agreement includes the requirement that we supply ancillary services with respect to the reserved capacity of the reserved units. The number of units identified as reserved capacity is gradually decreased based on the agreement. The decrease in reserved capacity, if Exelon Generation does not exercise its option to purchase the energy and capacity, provides us with the opportunity to sell the capacity to the open market during the later years of the agreement. Exelon Generation is able to exercise call options on available capacity with commensurate higher capacity charges during the five-year period. Exelon Generation has exercised its options on all optional capacity units for 2002. Exelon Generation is also committed to continue the agreement with respect to units having a capacity of 1,696 megawatts in 2003 and 2004 and has the option to terminate one or more individual coal units having a capacity of up to 3,949 megawatts for both of 2003 and 2004. Since Exelon Generation is able to dispatch the coal-fired stations as required for the duration of the agreement, compensation is also provided to us for the cost of startups, shutdowns and some low load operations, which is not covered by the normal energy charge rate.

The power purchase agreement sets forth different capacity charges for the summer months of June, July, August and September and the non-summer months of October through May. The reserved capacity payments are based on the contracted amounts identified in the power purchase agreement and are adjusted by a factor that is in part based on the group equivalent availability factor. If the group equivalent availability factor is higher than a specified threshold, then the adjustment factor calculation provides us with the opportunity to increase the normal monthly capacity payment, but if the group equivalent availability factor is lower than the minimum, then we are penalized by a loss in

the monthly capacity payment. The monthly capacity payment adjustment factor provides us with an incentive to maintain the individual units at high equivalent availabilities.

The appropriate group equivalent availability factor required in the calculation for potentially achieving the full monthly capacity payment for the coal-fired units is 65% for the summer months and 55% for the non-summer months. While the historic annual equivalent availability factors for the facilities have not consistently demonstrated the levels required in the power purchase agreement on an annual basis, we believe the average annual equivalent availability for the different unit types should be achievable based on data from similar units in the North American Electric Reliability Council availability data. The facilities have achieved forced outage rates consistent with the agreement availability levels following major rehabilitation work performed by Commonwealth Edison. However, our ability to achieve the desired monthly equivalent availability is largely a function of the operations and maintenance of the individual units. The 2001 equivalent availability factor of the coal-fired units was 82.9%, and the summer month availability factor was 92.9%, both of which are well above the targets set forth in the power purchase agreement.

In connection with the acquisition of the Collins Station, we entered into a five-year power purchase agreement with Commonwealth Edison which was also assigned to Exelon Generation. The agreement expires on December 31, 2004. This power purchase agreement was amended on July 12, 2000 and amended and restated on September 13, 2000. References to the "agreement" in this section are references to the power purchase agreement as amended and restated.

Under the agreement, Exelon Generation purchases capacity and has the right to purchase electric energy generated by the units at the Collins Station from us. Under the agreement, all units that are contracted to Exelon Generation during the term are considered reserved capacity. The agreement provides for capacity and energy payments. Exelon Generation is obligated to make a capacity payment for the units under contract, providing us revenue for fixed charges such as debt service, labor and insurance, and an energy payment for the electricity produced by these units and sold to Exelon Generation, compensating us for variable costs of production. Exelon Generation is obligated to dispatch and purchase a specified minimum amount of electric energy or pay an additional payment calculated under the agreement to meet this minimum purchase requirement. If Exelon Generation does not fully dispatch the units under contract, we may sell the excess energy to third parties, subject to several conditions.

The Collins Station power purchase agreement includes the requirement that we supply ancillary services with respect to the reserved capacity. Exelon Generation has the option to terminate this agreement in its entirety or with respect to any generating unit or units for each of 2003 and 2004 by giving us notice of its decision to terminate at least ninety days before each contract year.

The power purchase agreement divides the capacity charges into summer months of June, July, August and September and non-summer months of October through May. The capacity payments are based on the contracted amounts identified in the agreement and are adjusted by a factor that is in part based on the group equivalent availability factor. With respect to all electricity purchased under the agreement, Exelon Generation is obligated to pay: a monthly capacity charge for the reserved units which varies according to the time of year; a per megawatt energy hour charge which varies from $30 to $34 over the term of the agreement; various charges for start-up of the reserved units; low load charges that apply at any hour in which Exelon Generation schedules a reserved unit to operate at an output below a level specified in the agreement; and an annual settlement amount to the extent natural gas prices exceed a specified amount and Exelon Generation dispatches a minimum amount of electric energy. The 2001 equivalent availability factor of the Collins Station was 83.0%, and the summer month

availability factor was 99.1%, both of which are well above the targets set forth in the power purchase agreement.

In connection with the acquisition of Commonwealth Edison's Crawford, Fisk, Waukegan, Calumet, Joliet, Bloom, Electric Junction, Sabrooke and Lombard peaking units, we entered into a five-year power purchase agreement with Commonwealth Edison which was also assigned to Exelon Generation. The agreement expires on December 31, 2004.

Under this agreement, Exelon Generation purchases capacity and has the right to purchase from us electric energy generated by the peaking units. The agreement provides for capacity and energy payments to us. Exelon Generation has the right to receive and purchase the generating capacity for the peaking units. If Exelon Generation does not fully dispatch the units under contract, we may sell the excess energy to third parties, subject to several conditions.

The agreement divides the capacity charges into summer months of June, July, August and September and non-summer months of October through May. The reserved capacity payments are based on the contracted amounts identified in the agreement and are adjusted by a factor that is in part based on a capacity adjustment factor. Exelon Generation is obligated to pay a capacity charge for the reserved peaking units and a per megawatt hour energy charge of $75 to $95 for oil-fired energy and $40 to $60 for gas-fired energy. Exelon Generation may also be obligated to pay a bonus fee if a unit is operated at peak capacity or a payment calculated under the agreement if a specified minimum of generating capacity is not dispatched and purchased by Exelon Generation. Effective January 1, 2002, Exelon Generation exercised the option to terminate all of the oil peaker units (300 megawatts) but continued the agreement with respect to all other peaker units for 2002. Exelon Generation has the option to terminate this agreement in its entirety or with respect to any of the generating unit or units for each of 2003 and 2004 by giving us notice of its decision to terminate at least 90 days before each contract year.

Coal is the fuel for 5,646 megawatts of our generating capacity. The coal is purchased from several suppliers that operate mines in the Powder River Basin of Wyoming and Montana. The coal is purchased under a variety of supply agreements ranging from one year to more than ten years in length. All the coal is low sulfur, averaging less than 0.66 pounds of sulfur dioxide per million Btu's for the period since the date of transfer of the assets. The total volume of coal consumed annually is approximately 15,000,000 to 16,000,000 tons.

All coal is transported under long-term transportation agreements with the Union Pacific Railroad and Burlington Northern Santa Fe Railroad. The coal is delivered in unit trains of 115 to 126 railcars each. At December 31, 2001, we leased approximately 3,800 railcars to transport the coal from the mines to the generating stations. The railcar leases have terms that range from as short as one year to more than 17 years, with options to extend or purchase certain railcars at the end of the lease term. The coal is transported nearly 1,200 miles from the mines to the stations which are located in the greater Chicago area, except for Powerton Station, which is located near Pekin, Illinois.

Coal is delivered to two stations via river barges, which we have under charter. The coal is first delivered to the Will County Station in Romeoville, Illinois by unit trains where it is dumped from the railcars, blended to meet station specifications and loaded into river barges. These barges are towed by an independent contractor under a multi-year transportation agreement with us to the stations located inside the city limits of Chicago.

The 2,698 megawatt Collins Station is a residual fuel oil or gas-fired steam generating station. The principal fuel has been the lower cost natural gas since the units were converted to allow firing of natural gas in the mid-1990's. Approximately 3,200,000 barrels of usable on-site fuel oil storage exists at the station. Edison Mission Marketing & Trading, our marketing affiliate, purchases the natural gas and provides hedges for both fuel oil and natural gas. Most fuel oil purchasing is done, as necessary, by Edison Mission Energy Services, Inc., another affiliate, but we also sometimes buy small quantities for on-site plant use.

Approximately 1,195 megawatts of peaking capacity in the form of simple cycle combustion turbines are located throughout the northern part of Illinois. These units are fueled with either natural gas or distillate fuel oils, depending on the specific site. The natural gas is purchased by Edison Mission Marketing & Trading. Most of the fuel oil is purchased by Edison Mission Energy Services, Inc. under annual contracts with local suppliers.

Our contractual commitments for the purchase of coal and fuel oil and for the transport of coal, subject to adjustment, are currently estimated to aggregate $1.047 billion over the duration of the existing contracts, summarized as follows: $299 million in 2002; $181 million in 2003; $145 million in 2004; $138 million in 2005; $139 million in 2006 and $145 million thereafter, in each case subject to adjustment.

The operating performance of the stations, based on equivalent availability factors for the years 1997 to 2001, is shown below. The equivalent availability factor, a ratio expressed as a percentage, is the amount of production that each station was able to produce during a given time period divided by the amount of production that each unit would have produced if operated at its full capacity during that given time period.

Facility	1997	1998	1999	2000	2001
Collins	76.9%	79.4%	88.8%	86.9%	83.0%
Crawford	43.1%	67.8%	50.6%	82.0%	79.6%
Fisk	84.5%	75.0%	59.4%	93.9%	85.0%
Joliet Unit 6	86.7%	62.6%	89.9%	81.7%	78.5%
Joliet Units 7 and 8	67.9%	69.4%	81.1%	74.8%	73.1%
Powerton	64.3%	68.8%	71.5%	80.8%	88.8%
Waukegan	81.5%	75.9%	65.7%	83.7%	91.9%
Will County	64.8%	70.1%	51.7%	74.0%	79.4%
On-Site Peakers	94.0%	94.6%	51.3%	85.7%	81.9%
Off-Site Peakers	93.4%	83.3%	74.3%	86.1%	85.6%

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. We utilize state-of-the-art computerized maintenance systems to plan and schedule all maintenance activities. We also employ a preventative maintenance program complemented by new predictive maintenance technologies such as lubrication analysis, thickness testing, 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.

Station units at Joliet, Will County, Crawford, Waukegan and Fisk Stations and offsite peakers located at Electric Junction, Lombard, Calumet, Bloom and Sabrooke are connected to Commonwealth Edison's 138kV transmission system. The offsite peakers are connected via transmission substations, and the station units are connected through various circuit breakers and transformers. Power output from the Collins Station's units are connected to Commonwealth Edison's 765kV transmission system and 345kV transmission system. The two Joliet units subject to the lease transactions and the two Powerton units deliver their power into Commonwealth Edison's 345kV transmission system.

We maintain insurance coverages consistent with those normally carried by companies engaged in similar business and owning similar properties. Our insurance program includes all-risk property insurance, including business interruption, covering real and personal property, including losses from boilers, machinery breakdowns, and the perils of earthquake and flood, subject to specific sublimits. 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. Further, we have the benefit of title insurance. Limits and deductibles in respect of these insurance policies are comparable to those carried by other electric generating facilities of similar size.

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

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 compete more effectively 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 in Illinois commenced on October 1, 1999 for mostly large commercial and industrial customers, with full access, including all residential customers, scheduled by May 1, 2002.

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 station and that the station then operate in compliance with these permits and approvals.

While we believe that the requisite approvals for our existing projects 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 to 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 a state public utility commission may not have any jurisdiction to modify the terms of wholesale power sales, we cannot assure you that the power sales contracts of our operations will not be subject to adverse regulatory actions.

In December 1997, the Governor of Illinois signed into law the Electric Service Customer Choice and Rate Relief Law of 1997. We will refer to this law as the Illinois Electric Law. The Illinois Electric Law has required and is requiring electric utilities to file delivery services implementation plans for non-residential retail customers no later than March 1, 1999 and for residential customers no later than August 1, 2001 and to recover the costs associated with the provision of delivery services. The Illinois Electric Law also requires the Illinois Commerce Commission to adopt reliability rules for the transmission and distribution systems of Illinois utilities. These rules have been adopted and include reporting and penalty provisions that apply to Commonwealth Edison.

Illinois' transition to retail electric competition is being conducted in phases with approximately one-third of non-residential customers having had the opportunity to purchase electricity from alternative retail electric suppliers or electric utilities serving retail customers outside their service areas, effective October 1, 1999. Choice of suppliers is now available to all non-residential customers and choice for all residential customers will be available on or before May 1, 2002. Alternative retail electric suppliers include any person or company, other than an Illinois electric utility, that sells electricity to one or more retail electric customers in Illinois.

During the transition to full open access, customers that switch to alternative retail electric suppliers or electric utilities serving retail customers outside their service areas may be required to pay transition charges to compensate the utilities that previously supplied these customers for past investments, including investments in generating plants. The Illinois Electric Law calls for these transition charges to end no later than December 31, 2006, although some utilities may petition the Illinois Commerce Commission to extend the period for collection of transition charges until December 31, 2008.

The Illinois Electric Law provides that each Illinois electric utility that owns or controls transmission facilities or provides transmission services in Illinois, and is a member in the Mid-American Interconnected Network, shall submit for approval to the Federal Energy Regulatory Commission an application for establishing or joining an independent system operator. At least two entities with the potential to involve Commonwealth Edison's transmission facilities or services have submitted materials to the Federal Energy Regulatory Commission. These are the Midwest Independent System Operator and the Alliance Regional Transmission Operator. It is not possible at this time to determine which of these entities, or possibly another entity, ultimately will be involved with the management of the flow of electricity through Commonwealth Edison's transmission facilities.

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 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 under that Act by the Federal Energy Regulatory Commission provided incentives for the development of cogeneration facilities and small power production facilities using 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 the 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 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 of our 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 November 9, 1999, the Federal Energy Regulatory Commission issued an order 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.

Natural Gas Act. Our Collins Station and peaking units have the dual capability of burning natural gas or oil. Under the Natural Gas Act, the Federal Energy Regulatory Commission has jurisdiction over some sales of natural gas and over transportation and storage of natural gas in interstate commerce. The Federal Energy Regulatory Commission has granted blanket authority to all persons to make sales of natural gas without restriction but continues to exercise significant oversight with respect to transportation and storage of natural gas services in interstate commerce.

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 and foreign regulatory authorities with jurisdiction over projects located outside 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.

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 1,442 employees, approximately 1,045 of whom are covered by a collective bargaining agreement. Most of our employees were recruited and selected in accordance with the asset sale agreement by which we acquired the power generating assets from Commonwealth Edison, and are former employees of Commonwealth Edison. We employ a skilled and disciplined workforce that is well prepared to operate within a competitive and deregulated environment. Our staffing levels are comparable with benchmark standards for facilities of a similar size and type, and we have significantly improved equivalent availability and safety since taking over the operation and maintenance of these plants.

Under Illinois law and as a result of agreements with the union representing the physical, technical, and clerical employees at the time we acquired the facilities, wages, benefits, and working conditions are set. Under these agreements, we have the flexibility to manage the operations more efficiently than they were managed under the prior owner, and we are in the process of enhancing the training of our workforce in accordance with Edison Mission Energy's operating standards and guidelines.

Between early June and mid-October of 2001, we were in negotiations with the union that represents our employees to replace the expired collective bargaining agreement, covering wages and working conditions. The union authorized a strike that began on June 28, 2001. We operated the power generation plants during the strike. Negotiations concluded with a new four-year agreement that was ratified by our represented employees on October 16, 2001. Pursuant to our reinstatement process, employees began returning to work on October 22, 2001.

We own a fee interest in the following sites, with the exception of the Collins Station, the Powerton Station and the Joliet Station, as more particularly described below. The first eight listed sites are electric generating facilities, and the last nine listed sites are peaking units, the first four of which are located on the same sites as some of our electric generating facilities.

We purchased all the properties, with the exception of the Collins Station, from Commonwealth Edison in December 1999. We assigned the right to purchase Collins Station to third parties, who purchased the Collins Station, entered into leases with an affiliate of ours, who in turn leased the plant to us. The conveyance transaction involved Commonwealth Edison selling only a portion of its then owned properties to us. Commonwealth Edison retained the remaining portions of its properties for its own uses. We and Commonwealth Edison have various reciprocal permanent and temporary easements over our respective parcels for the location, use, maintenance and repair of those facilities and equipment that are used in connection with our operations and the operations of Commonwealth Edison.

As a result of the sale-leaseback of the Powerton and Joliet facilities in August 2000, we leased the property on which the generating units are located to the owner trusts under site leases, and the owner trusts in turn subleased their undivided ground interest in the property back to us under site subleases. The terms of the site leases and site subleases are 33.75 years for the Powerton property and 30 years for the Joliet property, with renewal options. Rent is paid in advance and/or arrears on each January 2 and July 2.

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

All the outstanding membership interest is, as of the date hereof, owned by Edison Mission Midwest Holding Co., which is an indirect wholly-owned subsidiary of Edison International. There is no market for the membership interest.

Dividends on the membership interest will be paid when declared by our board of managers. There were no cash dividends to Edison Mission Midwest Holding Co. in 2001 and 2000, respectively.

The following table sets forth our selected financial data for the periods indicated. On December 15, 1999, we acquired the power generation assets from Commonwealth Edison for a purchase price of approximately $4.9 billion. We had no significant activity before the acquisition. The selected financial statements for the period since our formation (July 12, 1999) through December 31, 1999 and for the years ended December 31, 2001 and 2000 were derived from our audited financial statements. These selected financial data are qualified in their entirety by the more detailed information and financial statements, including the notes to the financial statements, included in this report.

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

The following discussion contains forward-looking statements that reflect our current expectations and projections about future events based on our knowledge of present facts and circumstances and our assumptions about future events. In this discussion, the words "expects," "believes," "anticipates," "estimates," "intends," "plans" and variations of these words and similar expressions are intended to identify forward-looking statements. These statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. The information contained in this discussion is subject to change without notice. Unless otherwise indicated, the information presented in this section is with respect to Midwest Generation, LLC.

We are a special-purpose Delaware limited liability company formed on July 12, 1999 for the purpose of owning or leasing, making improvements to and operating the power generation assets we purchased from Commonwealth Edison. We are a wholly-owned subsidiary of Edison Mission Midwest Holdings Co., an indirect wholly-owned subsidiary of Edison Mission Energy and an indirect wholly-owned subsidiary of Edison International. We acquired the power generation assets on December 15, 1999 for a purchase price of approximately $4.9 billion, with adjustments for changes in the book value of inventories and pro-rations related to specific items including but not limited to taxes, rents and fees. Prior to the acquisition of these power generation assets, we had no significant business activity.

We also completed sale-leaseback transactions with respect to the Illinois peaker units in July 2000 and the Powerton and Joliet power facilities in August 2000. We sold these assets and entered into leasing agreements to control the use of the power plants during the terms of the leases while providing capital to finance its acquisition.

The aggregate megawatts we currently own or lease is approximately 9,539 MW and consist of the following:

In connection with the acquisition of these power generation assets, we entered into three five-year power purchase agreements for the coal-fired stations, the Collins Station, and the peaker stations, with Commonwealth Edison. Subsequently, Commonwealth Edison assigned its rights and obligations under these power purchase agreements to Exelon Generation. We derived 99% of our energy and capacity revenues from Exelon Generation under these power purchase agreements for both of the years ended December 31, 2001 and 2000. We have entered into a contract with a marketing affiliate for scheduling and related services and to market energy that is permitted to be sold under the power purchase agreements with Exelon Generation and to engage in hedging activities. The marketing affiliate also purchases fuel, other than coal, and enters into fuel hedging arrangements on our behalf.

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

As indicated above, we acquired the power generation assets on December 15, 1999 and, therefore, the 1999 results of operations included only a half month of activity and, accordingly, the comparison of a full year of operations in 2000 to a half month of activity in 1999 is not meaningful.

Operating revenues decreased $31.7 million in 2001 compared to 2000. The decrease is primarily due to losses from price risk management activities, as discussed in more detail below. Virtually all of our energy and capacity sales were made to Exelon Generation, the successor in interest to Commonwealth Edison, under the power purchase agreements. For 2001 and 2000, 99% of our total capacity and energy revenues were derived under our three power purchase agreements with Exelon Generation.

Our coal plants generated 26,627 GWh of electricity in 2001, compared to generating 27,117 GWh of electricity in 2000. The availability factor for 2001 was 82.9%, compared to 79.6% for 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 maintenance. We generally refer to unplanned maintenance as a forced outage. We had a forced outage rate of 9.5% and 9.8% during 2001 and 2000, respectively. The weighted average price for energy was $16.06/MWh in 2001, compared to $15.43/MWh in 2000. The increase in the weighted average price for energy is due to capacity and energy price escalation.

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

Losses from price risk management activities were $21.3 million in 2001. The losses primarily resulted from the change in market value of our futures contracts with respect to a portion of our anticipated fuel purchases through 2002 that did not qualify for hedge accounting under SFAS No. 133. Income from price risk management activities was $5.7 million in 2000. The income resulted from a gain realized for calendar year 2001 financial options entered into beginning August 2000 as a hedge of our price risk associated with expected natural gas purchases at the plants. During the fourth quarter of 2000, we determined that it was no longer probable that we would purchase natural gas at the plants during 2001. This decision resulted from sustained gas prices far greater than were contemplated when we originally projected our 2001 gas needs and the fact that we can use fuel oil interchangeably with natural gas at some of the plants.

Operating expenses increased $17.3 million in 2001 compared to 2000. Operating expenses consist of expenses for fuel, plant operations, depreciation and amortization and administrative and general expenses. The change in the components of operating expenses is discussed below.

Fuel costs decreased $49.6 million in 2001 compared to 2000. The decrease is primarily due to lower prices of fuel, consumption of more natural gas and proceeds from the sale of S0(2) allowances to an affiliate.

Plant operations expenses increased $60.1 million in 2001 compared to 2000. The increase was primarily due to planned maintenance costs that were accelerated during the strike and costs of additional security related to the strike during June through October 2001.

Depreciation and amortization expense decreased $1.0 million in 2001 compared to 2000. Depreciation expense primarily relates to the acquisition of the power generation assets we purchased from Commonwealth Edison which are being depreciated over periods ranging from 20 to 40 years. The amortization expense relates to the Powerton-Joliet facilities sale-leaseback and the Collins Station sale-leaseback which are being amortized over the term of the leases.

Administrative and general expenses increased $7.8 million in 2001 compared to 2000. The increase was primarily due to a $4.3 million bad debt allowance related to gas purchases with Enron Corp. and an increase in the administrative services charge from our parent due to higher levels of legal and labor costs.

Interest and other income increased $80.1 million in 2001 compared to 2000. The increase consisted primarily of interest income from loans to Edison Mission Energy, which occurred from the proceeds of our sale-leaseback transactions in the third quarter of 2000, and from short-term investments.

Interest expense increased $27.2 million in 2001 compared to 2000. Interest expense primarily relates to borrowings from Edison Mission Overseas Co., a wholly-owned subsidiary of our parent, under the subordinated loan agreements discussed below and interest expense related to the lease financings of the Collins, Powerton and Joliet Stations. In 2001 interest expense increased $42.8 million due to the lease financings completed in July and August 2000, partially offset by $15.6 million from lower interest rates on the borrowings under the subordinated loans, which are tied to variable interest rates.

We had effective income tax benefit rates of 36.6% and 39.0% in 2001 and 2000. The effective tax rates were different from the federal statutory rate of 35% due to state income taxes. The income tax benefit results from tax sharing agreements with our indirect parent, Edison International.

Net loss increased $1.3 million in 2001 compared to 2000. Although we expect to generate cash flow from operations, we expect to incur losses after depreciation, amortization and interest expense for several years. Our future results of operations will depend primarily on revenues from the sale of energy, capacity and other related products, and the level of our operating expenses.

We entered into a Master Purchase, Sale and Services Agreement with our marketing affiliate effective March 23, 2001, pursuant to which our marketing affiliate arranges for purchases and sales of the following products, including services related thereto: (i) electric energy and capacity; (ii) natural gas; (iii) fuel oil; and (iv) emissions allowances.

We compensate our marketing affiliate in accordance with the following table with respect to these transactions, and reimburse our marketing affiliate for brokers fees, taxes, and other reasonably incurred direct out-of-pocket expenses. Payment for these services is due within 30 days of billing.

Service		Compensation
Electric energy and/or capacity		$.02/MWh ($.02/MW-day for capacity)
Natural gas		$.02/MMBtu
Fuel oil		$.05/bbl
Emissions allowances		$.25/SO(2) allowance; and $25/NOx allowance

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. The amount due from the marketing affiliate was $5.7 million and $58.2 million at December 31, 2001 and 2000, respectively.

We entered into several transactions in 2001 through our marketing affiliate to sell surplus S0(2) allowances to other Edison Mission Energy affiliates. All transactions were completed at market price on the date of the transaction. Total consideration received was $10.2 million.

Proceeds arising from the Powerton-Joliet sale-leaseback transaction were used by us to make a loan to Edison Mission Energy. The loan is evidenced by four intercompany notes amounting to $1.367 billion. Edison Mission Energy is obligated to repay the principal on the notes in a series of installments on the dates and in the amounts set forth on a schedule to each note. Edison Mission Energy has paid and is required to pay interest on the notes on each January 2 and July 2 at a 8.30% fixed interest rate. All amounts due under the notes are due to be repaid in full on January 2, 2016. In addition to the four intercompany notes above relating to the Powerton-Joliet sale-leaseback, we loaned Edison Mission Energy $300 million from the sale-leaseback of the peaker power units. Edison Mission Energy is obligated to repay the principal on the note on July 9, 2010 at the latest and will periodically pay interest on the note at LIBOR plus 1.0475%. The effective rate was 3.53% at December 31, 2001. For more information on the sale-leasebacks, see "Contractual Obligations, Commitments and Contingencies."

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 our benefit. We believe the allocation methodologies are reasonable. Costs incurred for these programs and other services during the years ended December 31, 2001 and 2000 were $127.4 million and $149.4 million, respectively. Cost incurred during the period ended December 31, 1999 were not significant.

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 its loss experience is less than estimated.

We have also recorded a receivable from Edison Mission Energy of $169.9 million and $76.4 million at December 31, 2001 and December 31, 2000, respectively. At both dates, this relates to tax due under the tax sharing agreement with Edison Mission Energy. See "Notes to Financial Statements—Note 2, Summary of Significant Accounting Policies" for further discussion of the tax sharing agreement.

Midwest Generation EME, LLC is our indirect parent in Illinois and provides executive management, legal, human resources, accounting and other administrative services in Chicago on our behalf without charge. In connection with regulations of the Securities and Exchange Commission, the costs of these services must be recorded as part of our financial results, although we do not have a cash obligation to pay for these activities. The costs of these services, after tax, were $11.3 million and $7.8 million for the periods ended December 31, 2001 and 2000, respectively. We have reflected these activities as a non-cash contribution of services by our parent in the accompanying financial statements.

We entered into an agreement with our indirect parent, Midwest Generation EME, LLC to provide support services, including construction and construction management, operations and maintenance management, technical services and training, environmental, health and safety services, administrative and IT support, and other managerial and technical services needed to operate and maintain electric power facilities. Under the terms of the agreement, we reimburse our parent for actual costs incurred by functional area in providing support services, or in the case of specific tasks we request, the amount negotiated for the task. Actual costs billable under this agreement for the years ended December 31, 2001 and 2000 were $7.0 million and $8.3 million, respectively.

We entered into agreements with Edison Mission Energy Services, Inc. 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 the years ended December 31, 2001 and 2000 was $1.3 million and $1.0 million, respectively.

At December 31, 2001, we had cash and cash equivalents of $52.6 million compared to $15.7 million at December 31, 2000. Net working capital at December 31, 2001 was $233.5 million compared to $38.2 million at December 31, 2000.

Net cash used in operating activities was $39.1 million in 2001 compared to net cash provided by operating activities of $93.1 million in 2000. The change in cash provided by operating activities is primarily due to the increase in inventory and reduction in accrued liabilities.

Net cash provided by financing activities totaled $132.3 million in 2001, $1.4 billion in 2000 and $4.1 billion in 1999. In 2000, we received $1.367 billion of proceeds from the Powerton-Joliet sale-leaseback which were used to make a loan to Edison Mission Energy. In 1999, we entered into two subordinated loan agreements with an affiliate, Edison Mission Overseas, under which we borrowed $3.4 billion and received an equity contribution from our parent of $650 million to acquire our power generation assets.

Net cash used in investing activities totaled $56.3 million in 2001, $1.5 billion in 2000 and $4.1 billion in 1999. In 2001, we made upgrades to plant equipment. We expect to spend approximately $118 million in 2002 on capital expenditures, including environmental expenditures disclosed under "—Environmental Matters and Regulations—Federal—United States of America—Clean Air Act." These capital expenditures are planned to be financed by cash generated from operations. In 2000, we loaned $1.667 billion to Edison Mission Energy, received proceeds of $300 million from the Illinois peakers sale-leaseback and made upgrades to plant equipment following our acquisition in 1999. In 1999, we completed the acquisition of our power generation assets from Commonwealth Edison.

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

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

Collins Station Lease. In connection with the acquisition of the power generation assets from Commonwealth Edison, we assigned the right to purchase the Collins gas and oil-fired power plant to four third-party lessors. The third parties purchased the Collins Station for an aggregate price of $860 million and entered into leases of the plant with an affiliate of ours. Our affiliate entered into subleases with us. The subleases, which are being accounted for as a lease financing, each have an initial term of 33.75 years with payments due on a quarterly basis. If a lessor intends to sell its interest in the Collins Station, we have a right of first refusal to acquire the interest at fair market value.

The owner/lessor under the Collins lease issued notes in the amount of the lessor debt to Midwest Funding LLC, a funding vehicle created and controlled by the owner/lessor. These notes mature in January 2014 and are referred to as the lessor notes. Midwest Funding LLC, in turn, entered into a commercial paper and loan facility with a group of banks pursuant to which it borrowed the funds required for its purchase of the lessor notes. These borrowings are currently scheduled to mature in December 2004 and are referred to as the lessor borrowings.

refinance the lessor borrowings in accordance with guidelines set forth in the lease, but such refinancing is subject to the owner/lessor's approval. If the lessor borrowings are not refinanced by December 2004 because the owner/lessor's approval is not obtained or a refinancing is not commercially available, rent under the Collins lease would increase by approximately $8 million each three-month period.

Powerton and Joliet Facilities Sale-Leaseback. In August 2000, we entered into a sale-leaseback transaction with respect to the Powerton and Joliet power facilities located in Illinois to third-party lessors for an aggregate purchase price of $1.367 billion. We loaned the proceeds from the sale of the facilities to Edison Mission Energy. Under the terms of the leases (33.75 years for Powerton and 30 years for Joliet), we make semi-annual lease payments on each January 2 and July 2, which began January 2, 2001. Edison Mission Energy guarantees our payments under the leases. If a lessor intends to sell its interest in the Powerton or Joliet power facility, we have a right of first refusal to acquire the interest at fair market value. Under the terms of each lease, we may request a lessor, at its option, to refinance the lessor debt, which, if completed, would affect the base lease rent. We make lease payments from the principal and interest payments we receive on the loans to Edison Mission Energy as well as our cash flow from operating activities. We are also required to pay operating expenses and other expenses, including interest on and principal of our subordinated loans. The gain on the sale of the power facilities has been deferred and is being amortized over the term of the leases. For more information on our loans to Edison Mission Energy, see "Market Risk Exposures—Risks Related to Collection of Loans to Edison Mission Energy."

In the event of a default under the leases, each lessor can exercise all of its rights under the applicable lease, including repossessing the power plant and seeking monetary damages. Each lease sets forth a termination value payable upon termination for default and in certain other circumstances, which generally declines over time and in the case of default may be reduced by the proceeds arising from the sale of the repossessed power plant. A default under the terms of the Collins or Powerton and Joliet leases could result in a loss of our ability to use such power plant and could have a material adverse effect on our results of operations and financial position.

Illinois Peaker Sale-Leaseback. In July 2000, we entered into a sale-leaseback of equipment, primarily Illinois peaker power units, to a third-party lessor for $300 million. Under the terms of the five-year lease, we operate and sell the output of these units, and have the option to repurchase the units from their current owner/lessor at the end of the lease term for the fixed price of $300 million. Should this option not be exercised, the current owner/lessor can require us, as their agent, to sell the units and, if sold, they would no longer be available to us. The lease payments are structured to pay interest and fees of the lease debt plus a return to the owner/lessor on the equity invested in it. We agreed to pay the owner/lessor a deficiency payment if we do not exercise our purchase option and the proceeds from the sale of the equipment on their behalf is less than $300 million; provided, however, in no event can the deficiency payment exceed $255 million. Edison Mission Energy guaranteed our obligations under the lease. In order to finance its purchase of the equipment from us, the current owner/lessor obtained an equity investment of $9 million, and an additional $291 million through its issuance of senior notes in the amount of $255 million and subordinated notes in the amount of $36 million. In connection with the sale-leaseback, Midwest Peaker Holdings, Inc., a subsidiary of Edison Mission Energy, purchased $255 million of notes issued by the lessor, which accrue interest at LIBOR plus 0.65% to 0.95%, depending on Edison Mission Energy's credit rating. The notes are due and payable in 2005. The gain on the sale of the equipment has been deferred and is being amortized over the term of the operating lease.

We also have operating leases in place for other equipment, primarily leased barges and railcars that have terms which range from as short as one year to more than seventeen years.

We have entered into several fuel purchase agreements with various third-party suppliers for the purchase and/or transport of coal and fuel oil. The contracts range from one year to more than ten years in length. The minimum commitments are based on the contract provisions, which consist of fixed prices, subject to adjustment clauses.

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

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

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

We have guaranteed Edison Mission Midwest Holdings' (our parent) third-party debt in the amount of $1.7 billion at December 31, 2001. Our parent also pledged the membership interests in us to the lenders in connection with the third-party debt arrangements. See "Notes to Financial Statements—Note 4. Long-Term Debt."

Our primary market risk exposures arise from changes in commodity prices 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 three power purchase agreements with Exelon Generation, our revenues and results of operations during the estimated useful lives of the power plants will depend upon prevailing market prices for capacity, energy, ancillary services, fuel oil, coal, natural gas and associated transportation costs in the market area known as the MAIN Region and neighboring markets. Among the factors that influence the price of power in the MAIN Region are:

Virtually all our energy and capacity sales in 2001 were to Exelon Generation under the power purchase agreements, and a significant portion is likely to be sold to Exelon Generation during 2002. Under each of the power purchase agreements, Exelon Generation, upon notice by a given date, has the option in effect to terminate each agreement with respect to all or a portion of the units subject to it. In October 2001, Exelon Generation exercised the option under one of the power purchase agreements to terminate all of the oil peaker plants (300 megawatts), effective January 2002, but continued it with respect to all other peaker plants for 2002. Exelon Generation has the option to terminate the power purchase agreements related to the Collins Station and the peaker plants for both of 2003 and 2004. Under the power purchase agreement related to our coal units, Exelon Generation is committed to continue the agreement with respect to units having a capacity of 1,696 megawatts in 2003 and 2004 (the "committed coal units") and has the option to terminate, one or more individual coal units having a capacity of up to 3,949 megawatts for both of 2003 and 2004.

The energy and capacity from any units which do not remain subject to one of the power purchase agreements with Exelon Generation will be sold under terms, including price and quantity, to be negotiated with customers or into the so-called spot market. Thus, to the extent that Exelon Generation does not purchase our power for 2003 or 2004, we will be subject to the market risks related to the price of energy and capacity described above. Due to the volatility of market prices for energy and capacity during the past several years, we cannot predict whether or not Exelon Generation will elect to terminate any of the units currently subject to the power purchase agreements for which termination is permitted and, if they do, whether sales of energy and capacity to other customers and the market will be at prices sufficient to generate cash flow necessary to meet our obligations. As of December 31, 2001, we had not entered into forward energy sales contracts for our Illinois Plants other than those with Exelon Generation.

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

Our risk management policy allows for the use of derivative financial instruments through our marketing affiliate to limit financial exposure to fuel 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 that limit the amount of total net exposure that 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	$	(126	)	$	1,689
	Futures		(8,401	)		(8,189	)
	Swaps		—			93

A 10% increase in electricity forward prices would result in a $1.9 million increase at December 31, 2001 in the fair market value of energy contracts entered into by our marketing affiliate. A 10% decrease in electricity forward prices would result in a $1.9 million decrease at December 31, 2001 in the fair market value of energy contracts entered into by our marketing affiliate.

Interest rate changes affect the cost of capital needed to operate the facilities and our lease costs under the Collins Station lease and lease of Illinois peaker power units. Based on the amount of variable rate debt and leases outstanding on December 31, 2001, a 10% increase or decrease in short-term interest rates at December 31, 2001 would increase or decrease our annual income before taxes by approximately $5.2 million.

Substantially all of our revenues are derived under power purchase agreements with a single customer, and we may be adversely affected if that customer elects not to purchase power from us or fails to fulfill its obligations under those power purchase agreements.

During both 2001 and 2000, 99%, of our electric revenues were derived under three power purchase agreements with Exelon Generation Company, a subsidiary of Exelon Corporation. These agreements were entered into in connection with our December 1999 acquisition of the Illinois plants. Exelon Corporation is the holding company of Commonwealth Edison and PECO Energy Company, major utilities located in Illinois and Pennsylvania. Electric revenues attributable to sales to Exelon Generation are earned from capacity and energy provided by the Illinois plants under three five-year power purchase agreements expiring in 2004. If Exelon Generation were to fail or become unable to fulfill or choose to terminate some of its obligations under these power purchase agreements, we may not be able to find another customer on similar terms for the output of our power generation assets. Any material failure by Exelon Generation to make payments under these power purchase agreements could adversely affect our results of operations and liquidity.

Under each of the power purchase agreements, Exelon Generation, upon notice by a given date, has the option in effect to terminate each agreement with respect to all or a portion of the units subject to it. In October 2001, Exelon Generation exercised the option under one of the power purchase agreements to terminate all of the oil peaker plants (300 megawatts), effective January 2002, but continued it with respect to all other peaker plants for 2002. In each of 2003 and 2004, Exelon

Generation is committed to purchase 1,696 MW of capacity from specific coal units, but has the option to terminate all or any of the remaining coal units and all of the natural gas and oil-fired units with prior notice as specified under each agreement.

The energy and capacity from any units which do not remain subject to one of the power purchase agreements with Exelon Generation will be sold under terms, including price and quantity, to be negotiated with customers or into the so-called spot market. Thus, to the extent that Exelon Generation does not purchase our power for 2003 or 2004, we will be subject to the market risks related to the price of energy and capacity. Due to the volatility of market prices for energy and capacity during the past several years, we cannot predict whether or not Exelon Generation will elect to terminate any of the units currently subject to the power purchase agreements for which termination is permitted and, if they do, whether sales of energy and capacity to other customers and the market will be at prices sufficient to generate cash flow necessary to meet our obligations. As of December 31, 2001, we had not entered into forward energy sales contracts for the Illinois plants other than those with Exelon Generation.

Our ability to meet our obligations under long-term leases is dependent upon payment of interest and principal on our note receivable from Edision Mission Energy.

During 2000, we loaned $1.667 billion to Edison Mission Energy from the proceeds of the sale-leaseback of the Powerton/Joliet plants and the Illinois peaker units. Edison Mission Energy used the proceeds from these loans to repay corporate indebtedness. Interest and principal payments made by Edison Mission Energy to us under these intercompany loans provide funding for the payment of the lease rental payments owed by us. Our ability to meet our obligations under long-term leases is dependent upon payment of interest and principal on our note receivable from Edison Mission Energy.

Edison Mission Energy funds the interest and principal payments due under these intercompany loans from distributions from its subsidiaries, including us, cash on hand, and amounts available under its corporate lines of credit. A default by Edison Mission Energy in the payment of these intercompany loans could result in a shortfall of cash available to us to meet our lease and debt obligations. A default by us in meeting our obligations could in turn have a material effect on us.

Our operations are subject to extensive regulation by governmental agencies. We are subject to energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with our plants.

There is no assurance that the introduction of new laws or other future regulatory developments will not have a material adverse effect on our business, results of operations or financial condition, nor can we provide assurance that we will be able to obtain and comply with all necessary licenses, permits and approvals for our proposed energy projects. Currently, environmental advocacy groups and regulatory agencies in the United States have been focusing considerable attention on carbon dioxide emissions from coal-fired power plants and their potential role in the "global warming" issue. The adoption of laws and regulations to implement the carbon dioxide controls could adversely affect our coal-fired plants. Also, coal plant emissions of nitrogen and sulphur oxides, mercury and particulates are potentially subject to increased controls. See "—Environmental Matters and Regulations." If we cannot comply with all applicable regulations, our business, results of operations and financial condition could be adversely affected.

General operating risks and catastrophic events may adversely affect our plants.

The operation of power generating plants involves many risks, including start-up problems, the breakdown or failure of equipment or processes, performance below expected levels of output, the

inability to meet expected efficiency standards, operator errors, strikes, work stoppages or labor disputes and catastrophic events such as earthquakes, landslides, fires, floods, explosions or similar calamities. The occurrence of any of these events could significantly reduce revenues generated by our plants or increase their generating expenses, thus diminishing distributions by the projects to us and, as a result, our ability to meet our obligations as they become due. Equipment and plant warranties and insurance obtained by us may not be adequate to cover lost revenues or increased expenses and, as a result, we may be unable to fund principal and interest payments under our financing and lease obligations and may operate at a loss.

We have off-balance sheet activities related to operating leases. Our operating leases primarily include the Illinois Peakers lease and leased barges and railcars. See "—Contractual Obligations, Commitments and Contingencies" for a description of our leases and minimum lease obligations.

Air Quality. In June 2001, Illinois passed legislation mandating the Illinois Environmental Protection Agency to evaluate and issue a report to the Illinois legislature addressing the need for further emissions controls on fossil fuel-fired electric generating stations, including the potential need for additional controls on nitrogen oxides, sulfur dioxide and mercury. The study, which is to be submitted between September 30, 2003 and September 30, 2004, also requires an evaluation of incentives to promote renewable energy and the establishment of a banking system for certifying credits from voluntary reductions of greenhouse gases. The law allows the Illinois Environmental Protection Agency to propose regulations based on its findings no sooner than ninety days after the issuance of its findings, and requires the Illinois Pollution Control Board to act within one year on such proposed regulations. Until the Illinois Environmental Protection Agency issues its findings and proposes regulations in accordance with the findings, if such regulations are proposed, we cannot evaluate the potential impact of this legislation on the operations of our facilities.

Water Quality. The Illinois EPA is reviewing the water quality standards for the DesPlaines River adjacent to the Joliet Station and immediately downstream of the Will County Station to determine if the use classification should be upgraded. One of the limitations for discharges to the river that could be made more stringent if the existing secondary contact classification is changed would be the

allowable temperature of the discharges from Joliet and Will County. At this time no new standards have been proposed, so we cannot estimate the financial impact of this review.

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 anticipate upgrades to the environmental controls at our Illinois Plants to reduce nitrogen oxide emissions to result in expenditures of approximately $368 million for the 2002-2005 period.

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.

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, which we refer to as 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.

With respect to our liabilities arising under CERCLA or similar laws for the investigation and remediation of contaminated property, we accrue a liability to the extent the costs are probable and can be reasonably estimated. Generally, we do not believe the costs for environmental remediation for a particular site can be reasonably estimated before a remedial investigation has been completed for that particular site. In connection with due diligence conducted for the acquisition of our Illinois plants, we engaged a third-party consultant to conduct an assessment of the potential costs for environmental remediation of the plants. This assessment, which was based on information provided to us by the former owner of these plants, was less rigorous than a remedial investigation conducted in the course of a voluntary or required site cleanup. Accordingly, we have not recorded a liability for environmental remediation at these sites. We plan to perform or update individual site assessments as we believe is appropriate. As these assessments are completed, we will determine whether remedial investigation is needed.

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, which we refer to as 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 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, several utilities have reached a formal agreement with the United States (or reached agreements-in-principle) to resolve alleged NSR violations. All of the settlements have included the installation of additional pollution controls, supplemental environment projects, and the payment of

civil penalties. Some of the settlements have also included the retirement or repowering of coal-fired generating units. The agreements provide for a phased approach to achieving required emission reductions over the next 10 to 15 years. The total cost of some of these settlements exceeds $1 billion; the civil penalties agreed to by these utilities range between $1 million and $10 million. Because of the uncertainty created by the Administration's review of the NSR regulations and NSR enforcement proceedings, some of the settlements referred to above have not been finalized.

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."

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. On February 14, 2002, President Bush announced an objective to slow the growth of greenhouse gas emissions by reducing the amount of greenhouse gas emissions per unit of economic output by 18% by 2012 and to provide funding for climate-change related programs. The President's proposed program does not include mandatory reductions of greenhouse gas emissions. However, various bills have been, or are expected to be, introduced in Congress to require greenhouse gas emission reductions and to address other issues related to 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 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 "Midwest Generation, LLC Notes to Financial Statements—Note 2."

Currently, we are using the normal sales and purchases exception for our physical coal contracts. However, the Derivative Implementation Group of the Financial Accounting Standards Board under Statement No. 133 Implementation Issue Number C16 precludes contracts which have variable quantities from qualifying under the normal sales and purchases exception unless these quantities are contractually limited to use by the purchaser. Accordingly, we are evaluating the impact of this implementation guidance, which will be effective on April 1, 2002.

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.

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 Midwest Generation, LLC (a Delaware limited liability company) as of December 31, 2001 and 2000, and the related statements of operations, comprehensive loss, member's equity and cash flows for the years ended December 31, 2001 and 2000 and the period from inception (July 12, 1999) to December 31, 1999. These financial statements are the responsibility of the Company'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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Midwest Generation, LLC as of December 31, 2001 and 2000, and the results of its operations and its cash flows for the year ended December 31, 2001 and 2000 and the period from inception (July 12, 1999) to December 31, 1999 in conformity with accounting principles generally accepted in the United States.

Midwest Generation, LLC (the "Company"), a wholly-owned subsidiary of Edison Mission Midwest Holdings Co. ("Midwest Holdings"), an indirect wholly-owned subsidiary of Edison Mission Energy, an indirect wholly-owned subsidiary of Edison International, is a Delaware limited liability company formed on July 12, 1999 for the purpose of obtaining financing and acquiring, owning and operating multiple fossil-fuel electric generating units (collectively, the "Illinois Plants"), located within the state of Illinois, for the purpose of producing electric energy.

On December 15, 1999, the Company completed its acquisition of 100% of the ownership interests in the Illinois Plants and assumed specified liabilities from Commonwealth Edison. The accompanying financial statements reflect the operations of the Illinois Plants 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. The acquisition was financed through a capital contribution by Midwest Holdings of approximately $650 million and subordinate debt from another subsidiary of Midwest Holdings of approximately $3.4 billion.

Concurrent with the acquisition, the Company assigned its right to purchase the Collins Station, a 2,698 MW gas and oil-fired generating station located in Illinois, to four third-party entities. After this assignment, and the purchase of the facility by third parties, an affiliate of the Company leased and the Company entered into subleases of the Collins Station, each with a term of 33.75 years. These subleases have been accounted for as a lease financing for accounting purposes (see Note 9).

The aggregate megawatts purchased or leased as a result of the acquisition is approximately 9,539 MW and consist of the following:

In connection with the acquisition of these power generation assets, the Company entered into three five-year power purchase agreements for the coal-fired stations, the Collins Station, and the peaker stations with Commonwealth Edison. Subsequently, Commonwealth Edison assigned its rights and obligations under these power purchase agreements to Exelon Generation. The Company derived 99% of its energy and capacity revenues from Exelon Generation under these power purchase agreements for both of the years ended December 31, 2001 and 2000. The Company has entered into a contract with a marketing affiliate for scheduling and related services and to market energy that is permitted to be sold under the power purchase agreements with Exelon Generation and to engage in hedging activities. The marketing affiliate also purchases fuel, other than coal, and enters into fuel hedging arrangements on the Company's behalf.

Separate financial statements for the Company's operations are available only from the period since its acquisition of the Illinois Plants. There are no separate financial statements available with regard to the operations of the Illinois Plants prior to December 15, 1999 because their operations were fully integrated with, and their results of operations were consolidated into, those of

Commonwealth Edison. In addition, the electric output of the Illinois Plants was sold based on rates set by regulatory authorities. As a result of these factors and because electricity rates will now be set under power purchase agreements or by market forces, historical financial data with respect to the Illinois Plants are not meaningful or are not indicative of the Company's future results. The Company's future results of operations will depend primarily on revenues from the sale of energy, capacity and other related products, and the level of the Company's operating expenses.

Certain amounts in the prior period 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 revenues and expenses during the reporting period. Actual results could differ from those estimates.

The Company 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, natural gas, coal and fuel oil and is stated at the lower of weighted average cost or market. In 2001, the Company recorded a $5.1 million loss due to a lower of cost or market adjustment on its oil inventory at the Collins facility.

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

Power plant facilities		20 – 40 years
Emission allowances		25 – 40 years
Capitalized leased equipment		30 – 33.75 years
Furniture, office equipment and vehicles		3 – 7 years

As part of the acquisition of the Illinois Plants, the Company acquired emission allowances under the Environmental Protection Agency's Acid Rain Program. Although the emission allowances granted under this program are freely transferable, the Company intends to use substantially all the emission allowances in the normal course of its business to generate electricity. Accordingly, the Company has classified emission allowances expected to be used to generate power as part of property, plant and

equipment. Acquired emission allowances are amortized over the estimated lives of the Illinois Plants on a straight-line basis. Effective August 2000, the completion date of the Powerton/Joliet sale-leaseback transactions, the Company changed the period of amortization of emission allowances related to these plants to the periods of the respective leases.

The Company 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 its 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."

In connection with the acquisition, the Company assumed certain contracts for the future purchase of coal and transportation. The prices for coal and transportation as defined in the contracts exceeded the estimated fair market value of the coal and transportation contracts by $126.3 million at the date of acquisition, resulting in a liability. This liability is reduced as purchases are made over the term of the contacts.

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

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

Effective January 1, 2001, the Company 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 an asset or liability 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 Company recorded all derivatives at fair value unless the derivatives qualified for the normal sales and purchases exception. The Company's physical coal contracts currently qualify under this exception. The power purchase agreements with Exelon Generation did not qualify as derivatives. In 2000, the Company's affiliate entered into calendar year 2001 financial options as a

hedge of its price risk associated with expected natural gas purchases for the Collins Station. During the fourth quarter of 2000, the Company determined that it was no longer probable that it would purchase natural gas for the Collins Station during 2001. This decision resulted from sustained gas prices far greater than were contemplated when the Company originally projected its 2001 gas needs and the fact that the Company can use fuel oil interchangeably with natural gas at the Collins Station. Upon adoption of SFAS No. 133, the deferred gain of $20.8 million, after tax, which existed at the point the Company determined the purchase of natural gas being hedged by these options was no longer probable, was recorded as an unrealized holding gain reflected in accumulated other comprehensive income in the balance sheet. There was no cumulative effect on prior periods' net income resulting from the change in accounting for derivatives in accordance with SFAS No. 133.

Currently, the Company is using the normal sales and purchases exception for its physical coal contracts. However, the Derivative Implementation Group of the Financial Accounting Standards Board under Statement No. 133 Implementation Issue Number C16 precludes contracts which have variable quantities from qualifying under the normal sales and purchases exception unless such quantities are contractually limited to use by the purchaser. Accordingly, the Company is evaluating the impact of this implementation guidance, which will be effective on April 1, 2002.

The Company is included in the consolidated federal income tax and combined state franchise tax returns of Edison International. The Company calculates its income tax provision/(benefit) 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 Company and used in the Edison International consolidated tax return are recognized by the Company without regard to separate company limitations. The Company 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.

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 Company in the fourth quarter of 2001 and had no impact on its financial statements.

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

	2001			2000
Land	$	34,949		$	34,949
Power plant facilities		1,760,582			1,710,398
Emission allowances		867,350			867,350
Construction in progress		49,900			56,442
Equipment, furniture and fixtures		6,605			6,410
Plant and equipment under lease financing		2,227,000			2,227,000

		4,946,386			4,902,549
Accumulated depreciation and amortization		(304,466	)		(137,748	)

Property, plant and equipment, net	$	4,641,920		$	4,764,801

Property, plant and equipment includes assets which are capitalized under lease financing. The total consists of $860 million for the Collins Station and $1.367 billion for the aggregate purchase of the Powerton and Joliet stations. The Company recorded amortization expense related to the leased facilities of $68.1 million, $40.6 million and $1.1 million for 2001, 2000 and 1999, respectively. Accumulated amortization related to the leased facilities was $109.8 million, $41.7 million and $1.1 million at December 31, 2001, 2000 and 1999, respectively.

In December 1999, the Company entered into a subordinated loan agreement ("Subordinated Loan Agreement") with another subsidiary of Midwest Holdings, Edison Mission Overseas Co. ("Mission Overseas"), with terms matching those of a credit agreement as described further below under Parent Company Credit Agreement. Under the terms of the subordinated loan agreement, the Company is required to make payments to Mission Overseas similar to those payments made by Midwest Holdings under the Credit Agreement. As of December 31, 2001 and 2000, the borrowings under the Subordinated Loan Agreement were approximately $1.7 billion and $1.6 billion, respectively.

In December 1999, the Company also entered into a subordinated revolving loan agreement (the "Subordinated Revolving Line of Credit") with Mission Overseas for up to $2 billion. Amounts outstanding under the Subordinated Revolving Line of Credit bear interest at a fixed rate of 8.0% with

payments due quarterly. The outstanding principal balance is due in 2034. As of December 31, 2001 and 2000, total draws under the Subordinated Revolving Line of Credit were approximately $1.95 billion and $1.94 billion, respectively.

For the periods ended December 31, 2001 and 2000, under the Subordinated Revolving Line of Credit and the Subordinated Loan Agreement, the Company incurred and accrued interest charges of approximately $256.9 million and $272.6 million, respectively.

Years Ending December 31,
2002		$	—
2003			911,000
2004			808,308
2005			—
2006			—
Thereafter			1,952,680

	Total	$	3,671,988

In December 1999, Midwest Holdings entered into a credit agreement with a number of commercial lending institutions for a combination of loans and lines of credit aggregating $1.8 billion. The financing consisted of (1) an $840 million revolving credit facility due 2002, referred to as Tranche A, (2) an $839 million revolving credit facility due 2004, referred to as Tranche B, and (3) a $150 million working capital facility due 2004, referred to as Tranche C. In February 2000, Midwest Holdings issued commercial paper in the aggregate amount of $1.679 billion. The Tranche A and B loans were repaid with the proceeds of the commercial paper issuance. The Tranche A and Tranche B facilities were used to support the commercial paper issuance. At December 31, 2000, $803.9 million of commercial paper was outstanding. During 2001, this amount was repaid.

On May 9, 2000, Midwest Holdings entered into a Capex facility with a number of commercial lending institutions for a line of credit aggregating $71 million. At that time, the commercial paper program was increased to $1.75 billion and the Capex facility supported the additional issuance.

On December 13, 2000, the Capex facility expired. Midwest Holdings increased the Tranche A commitment to $911 million to pay off the Capex facility and extended the Tranche A maturity to 2003. On December 13, 2000, the Tranche B commitment amount was reduced to $816 million and on January 6, 2001, an additional reduction to $808.3 million occurred on the commitment under Tranche B. Under Tranche C, Midwest Holdings had available $150 million and $6.6 million of borrowing capacity at December 31, 2001 and 2000, respectively.

Amounts outstanding under the credit agreement bear interest at variable Eurodollar rates or Base rates as defined in the credit agreement, at the option of Midwest Holdings. If Midwest Holdings elects to pay Eurodollar rates, interest costs include a margin of 0.80% to 2.25% on Tranche A and 0.75% to 2.00% on Tranches B and C, depending on Midwest Holdings' debt rating. At December 31, 2001, the

margin was 1.20% on Tranche A and 1.15% on each of Tranches B and C. At December 31, 2000, the margin was 1.00% on Tranche A and 0.95% on each of Tranches B and C. The effective interest rate was 3.22% on Tranche A and 3.17% on Tranche B at December 31, 2001.

Additionally, Midwest Holdings pays a facility fee of 0.20% to 1.00% on Tranche A and 0.25% to 1.25% on each of Tranches B and C, depending on Midwest Holdings' current debt rating, on the total outstanding commitment irrespective of usage. At December 31, 2001, the facility fee was 0.30% on Tranche A and 0.35% on each of Tranches B and C. At December 31, 2000, the facility fee was 0.25% on Tranche A and 0.30% on each of Tranches B and C. Midwest Holdings also pays an agent bank fee of $50,000 per year. Midwest Holdings used the proceeds from the credit agreement to make a loan to Mission Overseas, which in turn loaned the funds to the Company.

Each of the subsidiaries of Midwest Holdings (including the Company) has executed full and unconditional guarantees in support of the borrowings under the credit agreement on a joint and several basis. Midwest Holdings has no material assets apart from investments in its subsidiaries.

The collateral for any borrowings under the credit agreement are secured by all of the assets of the Company, including a mortgage on real property and a security interest in all bank accounts, insurance policies and other intangible assets whether now owned or thereafter acquired.

Midwest Holdings has financial and non-financial debt covenants associated with its debt. Midwest Holdings, in order to make distributions, must maintain a specified debt service coverage ratio as follows: net cash flows over the aggregate of principal, interest, and fixed charges for a specified period exceeding 1.75 to 1.0.

The fair market value of the long-term debt approximates the carrying value due primarily to the frequent repricing of interest rates.

The Company's risk management policy allows for the use of derivative financial instruments through its marketing affiliate to limit financial exposure to fuel prices for non-trading purposes. Use of these instruments exposes the Company 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 Company's risk management policies. Policies are in place which limit the amount of total net exposure the Company 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 Company's marketing affiliate performs a series of "value at risk" analyses in its daily business to measure, monitor and control the Company's overall market risk exposure. The use of value at risk analysis allows the Company 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 Company'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	$	(126	)	$	1,689
	Futures		(8,401	)		(8,189	)
	Swaps		—			93

Income tax expense includes the current tax benefit from operating loss 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
	Price risk management		$	(1,623	)	$	16,793
	Lease financing			882			9,203
	Net operating losses			9,651			4,852

		Total	$	8,910		$	30,848

Deferred tax liabilities
	Accumulated depreciation difference		$	52,429		$	40,557
	State tax benefit			420			3,128
	Valuation allowance			4,799			—
	Other			8,137			—

		Total		65,785			43,685

Deferred taxes liability, net			$	56,875		$	12,837

The Company has $184.6 million of loss carryforwards at December 31, 2001 from Illinois state tax losses which expire beginning in 2020. The benefit for income taxes is comprised of the following:

			Years Ended December 31,
			Years Ended December 31,						Period from Inception (July 12, 1999) to December 31, 1999
			2001			2000			Period from Inception (July 12, 1999) to December 31, 1999
Current
	Federal		$	(87,631	)	$	(60,029	)	$	(13,061	)
	State			(12,846	)		(7,637	)		(1,536	)

		Total current	$	(100,477	)	$	(67,666	)	$	(14,597	)

Deferred
	Federal		$	35,043		$	8,489		$	6,407
	State			8,995			(2,520	)		461

		Total deferred		44,038			5,969			6,868

Benefit for income taxes			$	(56,439	)	$	(61,697	)	$	(7,729	)

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

		Years Ended December 31,
		Years Ended December 31,						Period from Inception (July 12, 1999) to December 31, 1999
		2001			2000			Period from Inception (July 12, 1999) to December 31, 1999
Accumulated depreciation difference		$	11,872		$	34,032		$	6,525
State tax benefit			(2,708	)		2,785			343
Price risk management			18,416			(16,793	)		—
Lease financing			8,321			(9,203	)		—
Net operating losses			—			(4,852	)		—
Other			8,137			—			—

	Total deferred provision	$	44,038		$	5,969		$	6,868

		Years Ended December 31,
		Years Ended December 31,						Period from Inception (July 12, 1999) to December 31, 1999
		2001			2000			Period from Inception (July 12, 1999) to December 31, 1999
Expected benefit for federal income taxes		$	(53,936	)	$	(55,325	)	$	(7,030	)
Decrease in taxes resulting from:
	State tax—net of federal benefit		(2,503	)		(6,372	)		(699	)

Benefit for income taxes		$	(56,439	)	$	(61,697	)	$	(7,729	)

Effective tax rate			36.6	%		39.0	%		38.5	%

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

The Company maintains a pension plan specifically for the benefit of its union employees. The Company'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. Information on plan assets and benefit obligations is shown below:

A portion of the Company'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 Company. 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 June 15, 2002. Under this agreement, a portion of these employees that retire prior to its expiration are covered under the postretirement benefit plans of Commonwealth Edison, their employer prior to the Company's acquisition in 1999. The Company 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 Company 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 Company has no legal obligation to do so. If the Company adopts a postretirement benefit plan for union-represented employees substantially the same as provided under the current Commonwealth Edison plan, the Company would record an adjustment to our prior service costs, if applicable, and amortize the impact over the estimated remaining service of covered employees. If no postretirement benefits are provided, the Company would treat this as a plan termination under SFAS No. 106 and record a gain during 2002. At the present time, the Company cannot predict the outcome of the 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 5.0% 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 $4.0 million. The effect on the annual aggregate service and interest costs would be $0.4 million. Decreasing the health care cost trend rate by one percentage point would decrease the accumulated obligation as of December 31, 2001 by $3.1 million. The effect on the annual aggregate service and interest costs would be $0.3 million.

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 5.0% 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 $19.2 million. The effect on annual aggregate service and interest costs would be $1.9 million. Decreasing the health care cost trend rate by one percentage point would decrease the accumulated obligation as of December 31, 2001 by $14.7 million. The effect on annual aggregate service and interest costs would be $1.5 million.

A 401(k) plan is maintained to supplement eligible employees' retirement income. The Company matches 100% of non-union employee contributions, up to 6% of such employees' annual compensation. The Company also matches 75% of contributions made by union employees, up to 6% of annual compensation. Employer contributions vest 20% per year. Contribution expense for the years ended December 31, 2001 and 2000 was $2.6 million and $2.2 million. Contribution expense incurred in 1999 was not material.

Electric power generated at the Company's power generation plants is sold under three power purchase agreements with Exelon Generation, in which Exelon Generation purchases capacity and has the right to purchase energy generated by the power generation plants. The Company initially entered into agreements with Commonwealth Edison on December 15, 1999, and they were subsequently assigned to Exelon Generation in January 2001. The power purchase agreements have a term of up to five years and provide for capacity and energy payments. Exelon Generation is obligated to make capacity payments for the power generation plants under contract and energy payments for the electricity produced by these plants and taken by Exelon Generation. The capacity payments provide the power generation plants revenue for fixed charges, and the energy payments compensate the power generation plants for variable costs of production. In October 2001, Exelon Generation terminated the power purchase agreement for the peaker units with respect to 300 megawatts of oil peakers, effective January 2002, but continued the agreement for all other peaker plants for 2002. In each of 2003 and 2004, Exelon Generation is committed to purchase 1,696 MW of capacity from specific coal units, but has the option to terminate all or any of the remaining coal units and all of the natural gas and oil fired units, with prior notice as specified under each agreement. If Exelon Generation does not fully dispatch the power generation plants under contract, the power generation plants may sell, subject to specified conditions, the excess energy at market prices to neighboring utilities, municipalities, third-party electric retailers, large consumers and power marketers on a spot basis. A bilateral trading infrastructure already exists with access to the Mid-America Interconnected Network and the East Central Area Reliability Council.

Pursuant to the acquisition documents for the purchase of generating assets from Commonwealth Edison, the Company committed to install one or more gas-fired electric generating units having an

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

At December 31, 2001, the Company had contractual commitments to purchase and/or transport coal and fuel oil. The contracts range from one year to more than ten years in length. Based on the contract provisions, which consist of fixed prices subject to adjustment, the minimum commitments are currently estimated to aggregate $1.047 billion over the duration of the existing contracts summarized as follows: 2002—$299 million; 2003—$181 million; 2004—$145 million; 2005—$138 million; 2006—$139 million; and thereafter—$145 million.

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

The Company expects 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, the Company anticipates upgrades to the environmental controls to reduce nitrogen oxides emissions at the power generation plants to result in expenditures of approximately $368 million over the next four years summarized as follows: 2002—$62 million; 2003—$57 million; 2004—$145 million and 2005—$104 million.

The Company has entered into interconnection agreements with Commonwealth Edison to provide interconnection services necessary to connect the Illinois Plants with its transmission systems. Unless

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

The Company employed 1,442 employees in Illinois, 1,045 of whom are covered by a collective bargaining agreement, at December 31, 2001. The collective bargaining agreement is due to expire on December 31, 2005. The Company also has a retirement health care and other benefits plan related to its represented employees, that is due to expire on June 15, 2002.

The Company has a lease financing with respect to its Collins Station and Powerton-Joliet stations. Each lease transaction is described in more detail below.

The Company also has operating leases in place with respect to its Illinois peaker power units and other equipment, primarily leased barges and railcars. The Illinois Peaker sale-leaseback is described in more detail below.

At December 31, 2001, the future operating and lease financing commitments were as follows:

Years Ending December 31,	Operating Leases		Lease Financing
2002	$	44,039	$	147,578
2003		34,749		147,578
2004		33,244		147,715
2005		20,053		191,388
2006		8,991		275,210
Thereafter		83,472		2,822,097

Total future commitments	$	224,548	$	3,731,566

Amount representing interest				(1,542,745	)

Net Commitments			$	2,188,821

Operating lease expense amounted to $32.5 million and $28.7 million in 2001 and 2000, respectively. Amounts for 1999 are insignificant.

In connection with the acquisition of the Illinois Plants, the Company assigned the right to purchase the Collins gas and oil-fired power plant to four third-party entities. The third parties purchased the Collins Station for $860 million and entered into leases of the plant with an affiliate of the Company. The affiliate entered into subleases of the plant with the Company. The subleases, which are being accounted for as a lease financing, each have an initial term of 33.75 years, with payments due on a quarterly basis. The base sublease rent includes both a fixed and variable component; the

variable component is impacted by movements in defined short-term interest rate indexes and the determination of such index as provided for under the related agreements. Under the terms of the subleases, the Company may request a lessor, at its option, to refinance the lessor's debt, which if completed would impact the base sublease rent. If a lessor intends to sell its interest in the Collins Station, the Company has a first right of refusal to acquire the interest at fair market value. Minimum lease payments (included in the table above) are $50.3 million in 2002, $50.3 million in 2003, $50.4 million in 2004, $50.3 million in 2005 and $90.3 million in 2006. At December 31, 2001, the total remaining lease payments were $1.5 billion.

The owner/lessor under the Collins lease issued notes in the amount of the lessor debt to Midwest Funding LLC, a funding vehicle created and controlled by the owner/lessor. These notes mature in January 2014 and are referred as the lessor notes. Midwest Funding LLC, in turn, entered into a commercial paper/loan facility with a group of banks pursuant to which it borrowed the funds required for its purchase of the lessor notes. These borrowings are currently scheduled to mature in December 2004 and are referred to as the lessor borrowings.

The rent under the Collins lease includes both a fixed component and a variable component, which is affected by movements in defined interest rate indices. If the lessor borrowings are not repaid at maturity, by a refinancing or otherwise, the interest rate on them would increase at specified increments every three months, which would be reflected in adjustments to the Collins lease rent payments. Under the Collins lease, we may request the owner/lessor to cause Midwest Funding LLC to refinance the lessor borrowings in accordance with guidelines set forth in the lease, but such refinancing is subject to the owner/lessor's approval. If the lessor borrowings are not refinanced by December 2004 because the owner/lessor's approval is not obtained or a refinancing is not commercially available, rent under the Collins lease would increase by approximately $8 million each three month period.

On August 24, 2000, the Company entered into a sale-leaseback transaction with respect to the Powerton and Joliet power facilities located in Illinois to third-party lessors for an aggregate purchase price of $1.367 billion. Under the terms of the leases (33.75 years for Powerton and 30 years for Joliet), the Company makes semi-annual lease payments on each January 2 and July 2, beginning January 2, 2001. If a lessor intends to sell its interest in the Powerton or Joliet power facility, the Company has a first right of refusal to acquire the interest at fair market value. Under the terms of each lease, the Company may request a lessor, at its option, to refinance the lessor debt, which if completed would affect the base lease rent. The lessor debt of $1.147 billion was obtained from the issuance by the Company of Pass-Through Certificates with terms ranging from nine to sixteen years with fixed interest rates ranging from 8.30% to 8.56%. The gain on the sale of the power facilities has been deferred and is being amortized over the term of the leases. Minimum lease payments (included in the table above) are $97.3 million in 2002, $97.3 million in 2003, $97.3 million in 2004, $141.1 million in 2005 and $184.9 million in 2006. At December 31, 2001, the total remaining lease payments were $2.2 billion.

On July 10, 2000, the Company entered into a sale-leaseback of equipment, primarily Illinois peaker power units, to a third-party lessor for $300 million. Under the terms of the five-year lease, the Company has a fixed price purchase option at the end of the lease term of $300 million. We agreed to pay the owner/lessor a deficiency payment if we do not exercise our purchase option and the proceeds from the sale of the equipment on their behalf is less than $300 million; provided, however, in no event can the deficiency payment exceed $255 million. Edison Mission Energy guaranteed our obligations under the lease. In connection with the sale-leaseback, Midwest Peaker Holdings, Inc., a subsidiary of Edison Mission Energy, purchased $255 million of notes issued by the lessor which accrue interest at LIBOR plus 0.65% to 0.95% depending on Edison Mission Energy's credit rating (3.43% at December 31, 2001). The notes are due and payable in five years. Minimum lease payments during the next four years (included in the table above) are $21.0 million in 2002, $21.0 million in 2003, $21.0 million in 2004 and $10.6 million in 2005. There are no minimum lease payments required beyond 2005. The gain on the sale of equipment has been deferred and is being amortized over the term of the operating lease.

The Company entered into a Master Purchase, Sale and Services Agreement with its marketing affiliate effective March 23, 2001, pursuant to which the Company's marketing affiliate arranges for purchases and sales of the following products, including services related thereto: (i) electric energy and capacity; (ii) natural gas; (iii) fuel oil; and (iv) emissions allowances.

The Company compensates its marketing affiliate in accordance with the following table with respect to these transactions, and reimburses its marketing affiliate for brokers fees, taxes, and other reasonably incurred direct out-of-pocket expenses. Payment for these services is due within 30 days of billing.

Service		Compensation
Electric energy and/or capacity		$.02/MWh ($.02/MW-day for capacity)
Natural gas		$.02/MMBtu
Fuel oil		$.05/bbl
Emissions allowances		$.25/SO(2) allowance; and $25/NOx allowance

The Company entered into several transactions in 2001 through its marketing affiliate to sell surplus S0(2) allowances to other Edison Mission Energy affiliates. All transactions were completed at market price on the date of the transaction. Total consideration received was $10.2 million.

Proceeds arising from the Powerton-Joliet sale-leaseback transaction (see Note 9) were used by the Company to make a loan to Edison Mission Energy. The loan is evidenced by four intercompany notes amounting to $1.367 billion. Edison Mission Energy is obligated to repay the principal on the notes in a series of installments on the dates and in the amounts set forth on a schedule to each note. Edison Mission Energy has paid and is required to pay interest on the notes on each January 2 and July 2 at an 8.30% fixed interest rate. All amounts due under the notes are due to be repaid in full on January 2, 2016. In addition to the four intercompany notes above relating to the Powerton-Joliet sale-leaseback, the Company loaned Edison Mission Energy $300 million from the sale-leaseback of the peaker power units (see Note 9). Edison Mission Energy is obligated to repay the principal on the note on July 9, 2010 at the latest and will periodically pay interest on the note at LIBOR plus 1.0475%. The effective rate was 3.53% at December 31, 2001.

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 Company, 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 Company participates in a common payroll and benefit program with all Edison International employees. In addition, the Company is billed for any direct labor and out-of-pocket expenses for services directly requested for the benefit of the Company. The Company believes the allocation methodologies are reasonable. Costs incurred for these programs and other services during the years ended December 31, 2001 and 2000 were $127.4 million and $149.4 million, respectively. Cost incurred during the period ended December 31, 1999 were not significant.

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

The Company has also recorded a receivable from Edison Mission Energy of $169.9 million and $76.4 million at December 31, 2001 and December 31, 2000, respectively. At both dates, this relates to tax due under the tax sharing agreement with Edison Mission Energy. See Note 2 for further discussion of the tax sharing agreement.

Midwest Generation EME, LLC is the Company's indirect parent in Illinois and provides executive management, legal, human resources, accounting and other administrative services in Chicago on the Company's behalf without charge. In connection with regulations of the Securities and Exchange Commission, the costs of these services must be recorded as part of the Company's financial results,

although the Company does not have a cash obligation to pay for these activities. The costs of these services, after tax, were $11.3 million and $7.8 million for the periods ended December 31, 2001 and 2000, respectively. The Company has reflected these activities as a non-cash contribution of services by its parent in the accompanying financial statements.

The Company entered into an agreement with its indirect parent, Midwest Generation EME, LLC to provide support services, including construction and construction management, operations and maintenance management, technical services and training, environmental, health and safety services, administrative and IT support, and other managerial and technical services needed to operate and maintain electric power facilities. Under the terms of the agreement, the Company reimburses its parent for actual costs incurred by functional area in providing support services, or in the case of specific tasks we request, the amount negotiated for the task. Actual costs billable under this agreement for the years ended December 31, 2001 and 2000 were $7.0 million and $8.3 million, respectively.

The Company entered into agreements with Edison Mission Energy Services, Inc. to provide fuel and transportation services related to coal and fuel oil. Under the terms of these agreements, the Company 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 the years ended December 31, 2001 and 2000 was $1.3 million and $1.0 million, respectively.

2001	First		Second		Third(i)		Fourth
Operating revenues	$	175,307		$	250,972		$	475,461	$	155,742		$	1,057,482
Operating income (loss)		(56,310	)		(8,631	)		220,951		(51,831	)		104,179
Provision (benefit) for income taxes		(48,104	)		(29,163	)		60,478		(39,650	)		(56,439	)
Net income (loss)		(77,120	)		(46,796	)		96,714		(70,462	)		(97,664	)

2000	First		Second		Third(i)		Fourth
Operating revenues	$	133,186		$	268,374		$	497,189	$	190,458		$	1,089,207
Operating income (loss)		(70,846	)		42,688			243,681		(62,333	)		153,190
Provision (benefit) for income taxes		(58,288	)		(14,122	)		66,626		(55,913	)		(61,697	)
Net income (loss)		(90,148	)		(22,879	)		99,951		(83,298	)		(96,374	)

Our members elect the Board of Managers. The Board of Managers may appoint officers as our business may require. Listed below are our current managers and executive officers and their positions as of March 22, 2002.

Name	Age	Position	Position Held Continuously Since
Georgia R. Nelson	52	Manager and President	July 1999
John K. Deshong	48	Manager and Vice President	August 2000
Ronald L. Litzinger	42	Manager and Vice President	August 2000
Kevin M. Smith	44	Manager, Vice President and Treasurer	July 1999
Raymond W. Vickers	59	Manager	July 1999
John P. Finneran, Jr.	42	Vice President	September 1999
Paul C. Gracey, Jr.	42	Vice President and General Counsel	June 2000
Fred W. McCluskey	42	Vice President	July 1999

Described below are the principal occupations and business activities of our managers and executive officers 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. From January 1996 until June 1999, Ms. Nelson was Senior Vice President, Worldwide Operations of Edison Mission Energy. 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. Mr. Deshong served as Regional Vice President of Tax, Americas Region of Edison Mission Energy from November 1998 to June 2000. From April 1997 to November 1998, Mr. Deshong served as Director, Tax Planning and Special Projects of Edison Mission Energy. Prior to joining Edison Mission Energy, Mr. Deshong was a 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 of Edison Mission Energy's Worldwide Operations. Mr. Litzinger served as Vice President of 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 of O&M Business Development and Manager of 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. Mr. Smith served as Treasurer of Edison Mission Energy from September 1992 to February 2000 and was elected a Vice President in 1994. During March 1998 until September 1999, Mr. Smith also held the position of Regional Vice President, Americas Region of Edison Mission Energy.

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 Skadden, Arps, Slate, Meagher & Flom LLP since 1989.

Mr. Finneran has been Vice President and Regional Vice President Finance, Americas Region of Edison Mission Energy since September 1999. From September 1998 to September 1999, Mr. Finneran

was Senior Vice President of Finance and Treasurer of Richfood Holdings. From January 1996 to September 1998, Mr. Finneran served as Chief Financial Officer and Treasurer of Dominion Energy.

Mr. Gracey has been Vice President of Edison Mission Energy since May 1998. 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.

Mr. McCluskey has been Vice President, Business Management of Edison Mission Energy since August 2000. From November 1998 to August 2000, Mr. McCluskey was Regional Vice President, Business Development. From February 1997 to November 1998, Mr. McCluskey was Director of Business Development. Mr. McCluskey was Manager of Operations from January 1995 to February 1997.

The officers of Midwest Generation, LLC 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
Membership interests		Edison Mission Midwest Holdings Co. One Financial Place 440 South LaSalle Street, Suite 3500 Chicago, Illinois 60605		100 units held directly and with exclusive voting and investment power		100%

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

Exhibit No.		Description
1.1		Purchase Agreement, dated as of August 17, 2000, among Midwest Generation, LLC, Edison Mission Energy and Credit Suisse First Boston Corporation and Lehman Brothers Inc. as representatives of the Initial purchasers, incorporated by reference to Exhibit 1.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
2.1		Asset Sale Agreement, dated March 22, 1999, between Commonwealth Edison Company and Edison Mission Energy as to the Fossil Generating Assets, incorporated by reference to Exhibit 2.5 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
3.1		Limited Liability Company Agreement of Midwest Generation, LLC effective as of July 12, 1999, incorporated by reference to Exhibit 3.3 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
3.2		Certificate of Formation of Midwest Generation, LLC, dated as of July 9, 1999, incorporated by reference to Exhibit 3.4 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.1		Pass-Through Trust Agreement A, dated as of August 17, 2000, between Midwest Generation, LLC and United States Trust Company of New York, as Pass-Through Trustee, made with respect to the formation of the Midwest Generation Series A Pass-Through Trust, and the issuance of 8.30% Pass-Through Certificates, Series A, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

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.

We have audited in accordance with auditing standards generally accepted in the United States, the financial statements of Midwest Generation, LLC included in this Form 10-K and have issued our report thereon dated March 25, 2002. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index in Item 14 is the responsibility of the Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

	Year Ended December 31, 2001			Year Ended December 31, 2000			Period from Inception (July 12, 1999) to December 31, 1999
	(in millions)
INCOME STATEMENT DATA
Operating revenues	$	1,057.5		$	1,089.2		$	23.7
Operating expenses		953.3			936.0			29.5

Operating income (loss)		104.2			153.2			(5.8	)
Interest and other expense		(258.3	)		(311.3	)		(14.3	)

Loss before income taxes		(154.1	)		(158.1	)		(20.1	)
Benefit for income taxes		56.4			61.7			7.7

Net loss	$	(97.7	)	$	(96.4	)	$	(12.4	)

	December 31,
	2001		2000		1999
	(in millions)
BALANCE SHEET DATA
Assets	$	6,772.6	$	6,730.4	$	5,183.9
Current liabilities		230.1		260.4		49.3
Long-term debt		3,672.0		3,518.7		3,422.0
Lease financing		2,179.7		2,188.8		860.0
Other long-term obligations		227.3		212.5		214.2
Member's equity		463.5		549.9		638.5

	December 31,
	2001			2000			1999
	(in millions)
CASH FLOW DATA
Cash provided by (used in) operating activities	$	(39.1	)	$	93.1		$	2.0
Cash provided by financing activities		132.3			1,446.5			4,072.0
Cash used in investing activities		(56.3	)		(1,524.0	)		(4,074.0	)

		2002		2003		2004		2005		2006		Thereafter		Total
		(in millions)
Contractual Obligations
Long-term debt to affiliate		$	—	$	911.0	$	808.3	$	—	$	—	$	1,952.7	$	3,672.0
Lease financing obligations			147.6		147.6		147.7		191.4		275.2		2,822.1		3,731.6
Operating lease obligations			44.0		34.7		33.2		20.1		9.0		83.5		224.5
Fuel supply contracts			298.6		181.1		144.5		137.8		139.5		145.7		1,047.2

	Total Contractual Cash Obligations	$	490.2	$	1,274.4	$	1,133.7	$	349.3	$	423.7	$	5,004.0	$	8,675.3

Commercial Commitments
Environmental improvements		$	59.0	$	—	$	—	$	—	$	—	$	—	$	59.0

Financial Statements:
	Report of Independent Public Accountants	40
	Balance Sheets at December 31, 2001 and 2000	41-42
	Statements of Operations for the years ended December 31, 2001, 2000 and for the period from inception (July 12, 1999) to December 31, 1999	43
	Statements of Comprehensive Loss for the years ended December 31, 2001, 2000 and 1999	44
	Statements of Member's Equity for the years ended December 31, 2001, 2000 and for the period from inception (July 12, 1999) to December 31, 1999	45
	Statements of Cash Flows for the years ended December 31, 2001, 2000 and for the period from inception (July 12, 1999) to December 31, 1999	46
	Notes to Financial Statements	47

Plant or Site	Location	Interest In Land	Type	Megawatts
Electric Generating Facilities
Collins Station (1)	Grundy County, Illinois	owned	oil/gas	2,698
Crawford Station	Chicago, Illinois	owned	coal	542
Fisk Station	Chicago, Illinois	owned	coal	327
Joliet Unit 6	Joliet, Illinois	owned	coal	314
Joliet Units 7 and 8	Joliet, Illinois	owned	coal	1,044
Powerton Station	Pekin, Illinois	owned	coal	1,538
Waukegan Station	Waukegan, Illinois	owned	coal	789
Will County Station	Romeoville, Illinois	owned	coal	1,092
Peaking Sites(2)
Crawford	Chicago, Illinois	owned	oil/gas	167
Fisk	Chicago, Illinois	owned	oil/gas	214
Joliet	Joliet, Illinois	owned	oil/gas	133
Waukegan	Waukegan, Illinois	owned	oil/gas	118
Calumet	Chicago, Illinois	owned	oil/gas	158
Bloom	Chicago Heights, Illinois	owned	oil/gas	54
Electric Junction	Aurora, Illinois	owned	oil/gas	188
Lombard	Lombard, Illinois	owned	oil/gas	74
Sabrooke	Rockford, Illinois	owned	oil/gas	89

		Total		9,539

			December 31,
			2001		2000
Assets
Current Assets
	Cash and cash equivalents		$	52,635	$	15,699
	Accounts receivable, net of allowance of $4,269 in 2001 and $0 in 2000			70,982		70,826
	Due from affiliates			175,592		134,609
	Fuel inventory			80,042		38,677
	Spare parts inventory			17,718		15,452
	Interest receivable from affiliate			58,885		16,864
	Other current assets			7,793		6,454

		Total current assets		463,647		298,581

Property, Plant and Equipment				4,946,386		4,902,549
	Less accumulated depreciation			304,466		137,748

		Net property, plant and equipment		4,641,920		4,764,801

Notes Receivable From Affiliate				1,667,000		1,667,000

Total Assets			$	6,772,567	$	6,730,382

			December 31,
			2001			2000
Liabilities and Member's Equity
Current Liabilities
	Accounts payable		$	17,192		$	14,600
	Accrued liabilities			66,789			139,345
	Due to affiliates			3,461			3,821
	Interest payable			83,892			56,242
	Interest payable to affiliates			41,233			25,455
	Liabilities under price risk management			8,401			—
	Current portion of lease financing			9,173			20,967

		Total current liabilities		230,141			260,430

Subordinated revolving line of credit with affiliate				1,952,680			1,942,239
Subordinated long-term debt with affiliate				1,719,308			1,576,456
Lease financing, net of current portion				2,179,648			2,188,821
Deferred taxes				56,875			12,837
Deferred coal and transportation costs				78,150			100,949
Benefit plans and other				92,232			98,750

Total Liabilities				6,309,034			6,180,482

Commitments and Contingencies (Notes 8 and 9)
Member's Equity
	Membership interests, no par value; 100 units authorized, issued and outstanding			—			—
	Additional paid-in capital			669,928			658,631
	Accumulated deficit			(206,395	)		(108,731	)

Total Member's Equity				463,533			549,900

Total Liabilities and Member's Equity			$	6,772,567		$	6,730,382

		Membership Interests		Additional Paid		Accumulated Deficit			Member's Equity
Balance at Inception (July 12, 1999)		$	—	$	—	$	—		$	—
	Cash contribution		—		650,000		—			650,000
	Non-cash contribution of services		—		816		—			816
	Net loss		—		—		(12,357	)		(12,357	)

Balance at December 31, 1999			—		650,816		(12,357	)		638,459
	Non-cash contribution of services		—		7,815		—			7,815
	Net loss		—		—		(96,374	)		(96,374	)

Balance at December 31, 2000			—		658,631		(108,731	)		549,900
	Non-cash contribution of services		—		11,297		—			11,297
	Net loss		—		—		(97,664	)		(97,664	)

Balance at December 31, 2001		$	—	$	669,928	$	(206,395	)	$	463,533

			Years Ended December 31,
			Union Plan						Non-Union Plan
			2001			2000			2001			2000
Change in Benefit Obligation
	Benefit obligation at beginning of year		$	7,790		$	209		$	4,807		$	3,251
	Service cost			5,526			6,642			872			1,025
	Interest cost			573			30			372			257
	Actuarial loss			954			911			376			274
	Benefits paid			(6	)		(2	)		—			—

		Benefit obligation at end of year	$	14,837		$	7,790		$	6,427		$	4,807

Change in Plan Assets
	Fair value of plan assets at beginning of year		$	5,576		$	—		$	—		$	—
	Actual return on plan assets			(387	)		(227	)		—			—
	Employer contributions			7,067			5,805			—			—
	Benefits paid			(6	)		(2	)		—			—

		Fair value of plan assets at end of year	$	12,250		$	5,576		$	—		$	—

Funded Status			$	(2,587	)	$	(2,214	)	$	(6,427	)		(4,807	)
Unrecognized net loss (gain)				3,382			1,335			636			274

Pension asset (liability)			$	795		$	(879	)	$	(5,791	)	$	(4,533	)

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	%		8.50	%		8.50	%		8.50	%

(a)	(1)	List of Financial Statements
		See Index to Financial Statements at Item 8 of this report.
	(2)	List of Financial Statement Schedules
		Schedule II—Valuation and Qualifying Accounts
		All other 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
	No reports on Form 8-K were filed during the quarter ended December 31, 2001.
(c)	Exhibits

4.2		Pass-Through Trust Agreement B, dated as of August 17, 2000, between Midwest Generation, LLC and United States Trust Company of New York, as Pass-Through Trustee, made with respect to the formation of the Midwest Generation Series B Pass-Through Trust, and the issuance of 8.56% Pass-Through Certificates, Series B, incorporated by reference to Exhibit 4.2 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.3		Form of 8.30% Pass-Through Certificate, Series A (included in Exhibit 4.1), incorporated by reference to Exhibit 4.3 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.4		Form of 8.56% Pass-Through Certificate, Series B (included in Exhibit 4.2), incorporated by reference to Exhibit 4.4 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.5		Indenture of Trust, Mortgage and Security Agreement (T1), dated as of August 17, 2000, between Powerton Trust I and United States Trust Company of New York, as Lease Indenture Trustee, incorporated by reference to Exhibit 4.5 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.5.1		Schedule identifying substantially identical agreement to Indenture of Trust, Mortgage and Security Agreement constituting Exhibit 4.5 hereto, incorporated by reference to Exhibit 4.5.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.6		Indenture of Trust, Mortgage and Security Agreement (T1), dated as of August 17, 2000, between Joliet Trust I and United States Trust Company of New York, as Lease Indenture Trustee, incorporated by reference to Exhibit 4.6 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.6.1		Schedule identifying substantially identical agreement to Indenture of Trust, Mortgage and Security Agreement constituting Exhibit 4.6 hereto, incorporated by reference to Exhibit 4.6.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.7		Facility Lease Agreement (T1), dated as of August 17, 2000, by and between Powerton Trust I, as Owner Lessor, and Midwest Generation, LLC, as Facility Lessee, incorporated by reference to Exhibit 4.7 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.7.1		Schedule identifying substantially identical agreement to Facility Lease Agreement constituting Exhibit 4.7 hereto, incorporated by reference to Exhibit 4.7.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

4.8		Facility Lease Agreement (T1), dated as of August 17, 2000, by and between, Joliet Trust I, as Owner Lessor, and Midwest Generation, LLC, as Facility Lessee, incorporated by reference to Exhibit 4.8 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.8.1		Schedule identifying substantially identical agreement to Facility Lease Agreement constituting Exhibit 4.8 hereto, incorporated by reference to Exhibit 4.8.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.9		Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Powerton Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.9 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.9.1		Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.9 hereto, incorporated by reference to Exhibit 4.9.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.10		Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Joliet Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.10 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.10.1		Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.10 hereto, incorporated by reference to Exhibit 4.10.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.11		Registration Rights Agreement, dated as of August 17, 2000, among Edison Mission Energy, Midwest Generation, LLC and Credit Suisse First Boston Corporation and Lehman Brothers Inc., as representatives of the Initial Purchasers, incorporated by reference to Exhibit 4.11 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.12		Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Powerton Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Powerton Generation I, LLC, as the Owner Participant, Edison Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee, and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Exhibit 4.12 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.12.1		Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.12 hereto, incorporated by reference to Exhibit 4.12.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

4.13		Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Joliet Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Joliet Generation I, LLC, as the Owner Participant, Edison Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Exhibit 4.13 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.13.1		Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.13 hereto, incorporated by reference to Exhibit 4.13.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.14		Promissory Note ($499,450,800), dated as of August 24, 2000, by Edison Mission Energy in favor of Midwest Generation, LLC, incorporated by reference to Exhibit 4.5 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
4.14.1		Schedule identifying substantially identical agreements to Promissory Note constituting Exhibit 4.14 hereto, incorporated by reference to Exhibit 4.5.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
4.15		Promissory Note, dated as of June 23, 2000, by Edison Mission Energy in favor of Midwest Generation, LLC, incorporated by reference to Exhibit 4.6 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.1		Guarantee, dated as of June 23, 2000, in favor of EME/CDL Trust and Midwest Generation, LLC made by Edison Mission Energy, incorporated by reference to Exhibit 10.85 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.2		Power Purchase Agreement (Crawford, Fisk, Waukegan, Will County, Joliet and Powerton Generating Stations), dated as of December 15, 1999, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.86 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.3		Power Purchase Agreement (Collins Generating Station), dated as of December 15, 1999, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.87 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.3.1		Amendment No. 1 to the Power Purchase Agreement, dated July 12, 2000, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.87.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.3.2		Amended and Restated Power Purchase Agreement (Collins Generating Station), dated as of September 13, 2000, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.87.2 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.4		Power Purchase Agreement (Crawford, Fisk, Waukegan, Calumet, Joliet, Bloom, Electric Junction, Sabrooke and Lombard Peaking Units), dated as of December 15, 1999, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.88 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.

10.5		Participation Agreement, dated as of June 23, 2000, among Midwest Generation, LLC, Edison Mission Energy, EME/CDL Trust, the Investor party to the Trust Agreement, Wilmington Trust Company, the Persons listed as Noteholders on Schedule I thereto, Citicorp North America, Inc. and Citicorp North America, Inc., incorporated by reference to Exhibit 10.89 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.5.1		Amendment One, dated as of August 17, 2000, by and among Midwest Generation, LLC, Edison Mission Energy, EME/CDL Trust, Citicorp Del-Lease, Inc., Wilmington Trust Company, Certain Noteholders Party Thereto, Citicorp North America, Inc. and Citicorp North America, Inc., incorporated by reference to Exhibit 10.89.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.6		Reimbursement Agreement, dated as of August 17, 2000, between Edison Mission Energy and Midwest Generation, LLC, incorporated by reference to Exhibit 10.90 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.7		Instrument of Assumption, dated as of December 15, 1999, by Midwest Generation, LLC in favor of Commonwealth Edison Company and Unicom Investment Inc., incorporated by reference to Exhibit 10.91 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.8		Subordination Agreement, dated as of December 15, 1999, among Midwest Generation, LLC, Edison Mission Overseas Co., and Citibank, N.A., incorporated by reference to Exhibit 10.92 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.9		Subordinated Loan Agreement, dated as of December 15, 1999, among Midwest Generation, LLC and Edison Mission Overseas Co., incorporated by reference to Exhibit 10.93 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.9.1		Amendment One to Subordinated Loan Agreement, dated as of May 22, 2001, by and among Midwest Generation, LLC and Edison Mission Overseas Co., incorporated by reference to Exhibit 10.93.1 to Midwest Generation, LLC's Form 10-Q for the quarter ended June 30, 2001.
10.10		Subordinated Revolving Loan Agreement, dated as of December 15, 1999, among Midwest Generation, LLC and Edison Mission Overseas Co., incorporated by reference to Exhibit 10.94 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.10.1		Amendment One to Subordinated Revolving Loan Agreement, dated as of May 22, 2001, by and among Midwest Generation, LLC and Edison Mission Overseas Co., incorporated by reference to Exhibit 10.94.1 to Midwest Generation, LLC's Form 10-Q for the quarter ended June 30, 2001.
10.11		Facility Lease Agreement (T1), dated as of December 15, 1999, between Collins Trust I and Collins Holdings EME, LLC., incorporated by reference to Exhibit 10.95 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

10.11.1		Schedule identifying substantially identical agreements to the Facility Lease Agreement constituting Exhibit 10.11 hereto, incorporated by reference to Exhibit 10.95.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.12		Amendment One, dated as of June 23, 2000, by and between Collins Trust I and Collins Holdings EME, incorporated by reference to Exhibit 10.96 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.12.1		Schedule identifying substantially identical agreements to the Amendment One constituting Exhibit 10.12 hereto, incorporated by reference to Exhibit 10.96.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.12.2		Amendment Two, dated as of August 17, 2000, by and between Collins Trust I and Collins Holdings EME LLC, incorporated by reference to Exhibit 10.96.2 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.12.3		Schedule identifying substantially identical agreements to the Amendment Two constituting Exhibit 10.12.2 hereto, incorporated by reference to Exhibit 10.96.3 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.13		Facility sublease Agreement (T1), dated as of December 15, 1999, by and among Collins Holdings EME, LLC, Midwest Generation, LLC and Collins Trust I, incorporated by reference to Exhibit 10.97 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.13.1		Schedule identifying substantially identical agreements to the Facility Sublease Agreement constituting Exhibit 10.13 hereto, incorporated by reference to Exhibit 10.97.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.14		Participation Agreement (T1), dated as of December 15, 1999, among Midwest Generation, LLC, Collins Holdings EME, LLC, Collins Trust I, Wilmington Trust Company, Collins Generation I, LLC, Edison Mission Midwest Holdings Co., Midwest Funding LLC, Bayerische Landesbank International S.A., Bayerische Landesbank Girozentrale, and Citibank, N.A., incorporated by reference to Exhibit 10.98 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.14.1		Schedule identifying substantially identical agreements to the Participation Agreement constituting Exhibit 10.14 hereto, incorporated by reference to Exhibit 10.98.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

10.15		Amendment One, dated as of May 9, 2000, by and among Collins Holdings EME, LLC, Collins Trust I, Wilmington Trust Company, Collins Generation I, LLC, Edison Mission Midwest Holdings Co., Midwest Generation, LLC, Midwest Funding LLC, Bayerische Landesbank International S.A., Bayerische Landesbank Girozentrale and Citibank, N.A., incorporated by reference to Exhibit 10.99 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.15.1		Schedule identifying substantially identical agreements to the Amendment One constituting Exhibit 10.15 hereto, incorporated by reference to Exhibit 10.99.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.16		Amendment Two, dated as of June 23, 2000, by and among Collins Holdings EME, LLC, Collins Trust I, Wilmington Trust Company, Collins Generation I, LLC, Edison Mission Midwest Holdings Co., Midwest Generation, LLC, Midwest Funding LLC, Bayerische Landesbank International S.A., Bayerische Landesbank Girozentrale, and Citibank, N.A., incorporated by reference to Exhibit 10.100 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.16.1		Schedule identifying substantially identical agreements to the Amendment Two constituting Exhibit 10.16 hereto, incorporated by reference to Exhibit 10.100.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.17		Amendment Three, dated as of August 17, 2000, by and among Collins Holdings EME, LLC, Collins Trust I, Wilmington Trust Company, Collins Generation I, LLC, Edison Mission Midwest Holdings Co., Midwest Generation, LLC, Midwest Funding LLC, Bayerische Landesbank International S.A., Bayerische Landesbank Girozentrale, and Citibank, N.A., incorporated by reference to Exhibit 10.101 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.17.1		Schedule identifying substantially identical agreements to the Amendment Three constituting Exhibit 10.17 hereto, incorporated by reference to Exhibit 10.101.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.18		Guarantee by Midwest Generation, LLC in favor of the Administrative Agent, dated as of December 15, 1999, incorporated by reference to Exhibit 10.102 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.19		Midwest OP Lease Guaranty made by Midwest Generation, LLC, dated as of December 15, 1999, incorporated by reference to Exhibit 10.103 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.19.1		Schedule identifying substantially identical agreements to the Midwest OP Lease Guaranty constituting Exhibit 10.19 hereto, incorporated by reference to Exhibit 10.103.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

10.20		Midwest Lessor Lease Guaranty (T1) made by Midwest Generation, LLC, dated as of December 15, 1999, incorporated by reference to Exhibit 10.104 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.20.1		Schedule identifying substantially identical agreements to the Midwest Lessor Lease Guaranty constituting Exhibit 10.20 hereto, incorporated by reference to Exhibit 10.104.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.21		Pledge Agreement, dated as of August 17, 2000, between Midwest Generation, LLC and Citibank, N.A., incorporated by reference to Exhibit 10.105 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.21.1		Schedule identifying substantially identical agreements to the Pledge Agreement constituting Exhibit 10.21 hereto, incorporated by reference to Exhibit 10.105.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.22		Lease Agreement, dated as of June 23, 2000, between Midwest Generation, LLC and EME/CDL Trust, incorporated by reference to Exhibit 10.106 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.23		Reimbursement Agreement I, dated as of December 15, 1999 entered into between Bayerische Landesbank International S.A. and Midwest Generation, LLC, incorporated by reference to Exhibit 10.107 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.23.1		Schedule identifying substantially identical agreements to the Reimbursement Agreement I constituting Exhibit 10.23 hereto, incorporated by reference to Exhibit 10.107.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.24		Credit Agreement, dated as of December 15, 1999, among Edison Mission Midwest Holdings Co., Certain Commercial Lending Institutions, and The Chase Manhattan Bank, incorporated by reference to Exhibit 10.108 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.24.1		Amendment One, dated as of May 9, 2000, by and among Edison Mission Midwest Holdings Co. and each of certain commercial lending institutions party thereto, incorporated by reference to Exhibit 10.108.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.24.2		Amendment Two, dated as of June 23, 2000, by and among Edison Mission Midwest Holdings Co., The Chase Manhattan Bank and each of certain commercial lending institutions party thereto, incorporated by reference to Exhibit 10.108.2 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.

10.24.3		Amendment Three, dated as of August 17, 2000, by and among Edison Mission Midwest Holdings Co., The Chase Manhattan Bank and each of certain commercial lending institutions party thereto, incorporated by reference to Exhibit 10.108.3 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
10.24.4		Amendment Four, dated as of December 12, 2000, by and among Edison Mission Midwest Holdings Co., The Chase Manhattan Bank and each of certain commercial lending institutions party thereto, incorporated by reference to Exhibit 10.108.4 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
21		List of Subsidiaries of Midwest Generation, LLC.*
99		Letter from Midwest Generation, LLC Regarding Assurance Letter From Arthur Andersen LLP.*

		MIDWEST GENERATION, LLC (REGISTRANT)
		By:		/s/ GEORGIA R. NELSON Georgia R. Nelson, Manager and President
		Date:		March 28, 2002

Signature	Title	Date

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

			Additions
Description		Balance at Beginning of Year	Charged to Costs and Expenses		Charged to Other Accounts	Deductions	Balance at End of Year
Year Ended December 31, 2001
	Allowance for doubtful accounts	—	$	4,269	—	—	$	4,269
Year Ended December 31, 2000
	Allowance for doubtful accounts	—		—	—	—		—
Year Ended December 31, 1999
	Allowance for doubtful accounts	—		—	—	—		—