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

300 Exelon Way
Kennett Square, Pennsylvania 19348
(610)765-8200
http://www.exeloncorp.com
(Address, including zip code and telephone number, including
area code, of Registrant's principal executive offices)

John L. Settelen, Jr.
Vice President and Controller
300 Exelon Way
Kennett Square, Pennsylvania 19348
(610)765-5978
(Name, address, including zip code and telephone number, including
area code, of agent for service)

Approximate date of commencement of proposed sale to the public: As soon as practicable after this registration statement becomes effective.

If any of the securities being registered on this Form are to be offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

The Registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Offer to Exchange
$700,000,000 6.95% Senior Notes Due 2011 (Exchange Notes)
Which have been registered under the Securities Act

For Any and All Outstanding
$700,000,000 6.95% Senior Notes Due 2011
Which have not been so registered

Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of those exchange notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for original notes where the original notes were acquired by the broker-dealer as a result of market-making activities or other trading activities. We have agreed that, starting on the Expiration Date (as defined herein) and ending on the close of business one year after the Expiration Date, we will make this prospectus available to any broker-dealer for use in connection with any such resale. See "Plan of Distribution."

Please see "Risk Factors" beginning on page 7 for a discussion of factors you should consider in connection with the exchange offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of the exchange notes or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

		Page
WHERE TO FIND MORE INFORMATION		i
PROSPECTUS SUMMARY		1
RISK FACTORS		7
FORWARD-LOOKING STATEMENTS		11
USE OF PROCEEDS		12
CAPITALIZATION		13
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		15
BUSINESS		31
MANAGEMENT		61
COMPENSATION		62
CERTAIN TRANSACTIONS		73
THE EXCHANGE OFFER		77
DESCRIPTION OF THE EXCHANGE NOTES		85
PLAN OF DISTRIBUTION		98
LEGAL OPINIONS		99
EXPERTS		99
INDEX TO FINANCIAL STATEMENTS		F-1

When we refer to the term "note" or "notes," we are referring to both the original notes and the exchange notes to be issued in the exchange offer. When we refer to "holders" of the notes, we are referring to those persons who are the registered holders of notes on the books of the registrar appointed under the indenture. Unless the context otherwise indicates, all references to "we," "us" or "our" in this prospectus mean Exelon Generation Company, LLC, a Pennsylvania limited liability company, and its consolidated subsidiaries.

No dealer, salesperson or other person is authorized to give any information or to represent anything not contained in this prospectus. You must not rely on any unauthorized information or representations. This prospectus is an offer only of the exchange notes to be issued in exchange for the original notes, but only under circumstances and in jurisdictions where it is lawful to do so. The information contained in this prospectus is current only as of its date.

In connection with the exchange offer, we have filed with the Securities and Exchange Commission (the "SEC") a registration statement under the Securities Act of 1933, as amended (the "Securities Act"), which offers to exchange the original notes for exchange notes. As permitted by SEC rules, this prospectus omits information included in the registration statement. For a more complete understanding of this exchange offer, you should refer to the registration statement, including its exhibits.

The public may read and copy any reports or other information that we file with the SEC at the SEC's public reference room, Room 1024 at Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, or at the SEC's regional offices located at 233 Broadway, New York, New York 10279, and Suite 1400, 500 West Madison Street, Chicago, Illinois 60661. The public may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. These documents are also available to the public from commercial document retrieval services and at the web site maintained by the SEC at http://www.sec.gov. You may also obtain a copy of the exchange offer registration statement at no cost by writing us at the following address:

Exelon Generation Company, LLC
Attn: Investor Relations
10 South Dearborn Street, 36^th Floor
P.O. Box 805379
Chicago, Illinois 60680-5379

The following information is qualified in its entirety by the more detailed information and financial statements appearing elsewhere in this prospectus. An investment in the exchange notes involves certain risks relating to our business, prospects, financial condition and results of operations and certain other risks relating to the terms of the exchange notes. These risks are described in "Risk Factors" beginning on page 7.

This exchange offer applies to $700,000,000 aggregate principal amount of the original notes. The terms of the exchange notes will be the same as the original notes, except that the exchange notes will not contain language restricting their transfer, and holders of the exchange notes generally will not be entitled to further registration rights under the registration rights agreement. The exchange notes will be issued under the same indenture as the original notes.

The following summary contains basic information about Exelon Generation Company, LLC. It may not contain all of the information that may be important to you in making a decision to exchange your original notes for the exchange notes. You should read this entire prospectus, and the documents to which we refer, before making your decision.

We are one of the largest competitive electric generation companies in the United States, as measured by owned and controlled megawatts. We directly own generation assets in the Mid-Atlantic and Midwest regions with net capacity of 19,715 MW, including 14,250 MW of nuclear capacity. We also control another 16,245 MW of capacity in the Midwest, Southeast and South Central regions through long-term power purchase agreements.

In addition to our own generation facilities, we own a 49.9% interest in Sithe Energies, Inc. with an option to purchase, beginning in December 2002, the remaining 50.1% interest. Sithe develops, owns and operates generation facilities and currently has 8,422 MW of capacity in operation, under construction or in advanced development. We also own a 50% interest in AmerGen Energy Company, LLC, which owns three nuclear stations with total generation capacity of 2,398 MW of which our interest is 1,199 MW.

Our Power Team division is a major wholesale marketer of energy that uses our generation portfolio, transmission rights and expertise to provide generation to wholesale customers under long- and short-term contracts. Power Team is responsible for supplying the load requirements of our utility affiliates Commonwealth Edison Company (ComEd) and PECO Energy Company (PECO). Power Team also buys and sells power in the wholesale spot markets.

We were formed on December 27, 2000 as a Pennsylvania limited liability company. We are an indirect wholly owned subsidiary of Exelon Corporation, a public utility holding company. Exelon is the result of the merger in October 2000 between Unicom Corporation, the former parent company of ComEd, and PECO. As part of a corporate restructuring of Exelon effective January 1, 2001, the power generation assets and the wholesale power marketing businesses of ComEd and PECO were transferred to us.

Our business strategy is to develop a national generation portfolio with fuel and dispatch diversity. To implement this strategy, we plan to:

Grow Our Generation Portfolio. We intend to continue to grow our generation portfolio through a disciplined approach to asset acquisitions, development of new plants, innovative applications of technology, joint ventures and long-term off-take contracts.

Drive Cost and Operational Leadership through Proven Fleet Management and Economies of Scale. Our goals are to increase fleet output and to improve fleet efficiency while sustaining operational safety. We intend to achieve these results in our nuclear fleet by increasing capacity factors over historic levels, reducing refueling outage duration and increasing our generation capacity through power uprates and other modifications. We applied to the Nuclear Regulatory Commission (the "NRC") in July 2001 for extension of the Peach Bottom 2 and 3 licenses and we expect to apply for extensions of the operating licenses for Dresden 2 and 3 and Quad Cities in 2003. AmerGen is also reviewing the potential for license extensions for Oyster Creek and Three Mile Island.

Optimize the Value of Our Low-Cost Generation Portfolio through Our Power Marketing Expertise. Power Team is responsible for optimizing the revenues of our generation assets through long- and short-term contracts and spot-market sales. Power Team also contracts for access to additional generation through bilateral long- and short-term power purchase agreements and spot-market purchases. By using real-time market information, Power Team manages the efficient dispatch of both our owned and contracted generation.

We believe that we are well positioned to play a leading role in the competitive energy industry because of a number of key strengths:

Competitive, Low-Cost Fleet of Generation Assets. Our low-cost advantage is driven by our ownership of or investment in 11 nuclear generation stations, consisting of 19 units, with net capacity totaling 15,449 MW. Our nuclear plants benefit from stable fuel costs, minimal environmental impact from operations and a safe operating history. In addition, our fuel diversity includes oil, coal, gas, water and wind.

Operating Experience and Expertise. We have achieved superior operating performance in our generation business through the leadership of a deep and experienced management team. We benefit from a coordinated approach to fleet management that includes the sharing of "best-in-class" practices across our organization and broad employee recognition that exceptional performance is required to succeed in a competitive environment.

Critical Mass of Generation Capacity with Economies of Scale. The generation assets transferred to us by ComEd and PECO and our investments in Sithe and AmerGen provide critical mass and a leadership position in the new energy markets. As the largest generator of nuclear power in the United States, we can take advantage of our scale and scope to negotiate favorable terms for the materials and services that our business requires.

Stable Revenue Streams under Long-Term Contracts with ComEd and PECO. We have entered into agreements to supply the load requirements of ComEd and PECO through 2004 and 2010, respectively. In 2001, sales to ComEd and PECO under these agreements accounted for approximately 58% of our revenues and the remaining 42% were in the wholesale market. Less than 4% of our sales represented transactions entered into for trading purposes.

In addition to the information contained elsewhere in this prospectus, you should carefully consider the risks described below. Each of the following factors could have a material adverse effect on our business and could result in a loss or a decrease in the value of your investment.

Our financial performance depends on the operation of our generation assets.

Deterioration in the operation of our power plants may adversely affect our financial performance as a result of lower revenues, increased operating expenses and higher maintenance costs.

Deterioration in the operation of Sithe or AmerGen plants also may adversely affect our financial performance.

Energy supplied by third-party generators pursuant to long-term agreements represents a significant portion of our overall capacity. The assets owned by these generators are subject to the same operational risks described above. In addition, performance under these power supply agreements may depend on the generator's financial condition. As a result, our financial performance depends on the ability of these generators to deliver capacity and energy under their contracts. Our largest power supply contract is with Midwest Generation, LLC, an affiliate of Southern California Edison Company, whose troubled financial condition was the subject of much media attention. To the extent the financial condition of Southern California Edison or its parent, Edison International, deteriorates, we cannot predict what impact, if any, this would have on Midwest Generation's ability to supply capacity and energy to us.

We have agreed to supply our affiliates ComEd and PECO with their respective load requirements through 2006 and 2010, respectively. Both ComEd and PECO are obligated to provide energy to all customers in their service territories who do not select an alternative energy supplier. In 2001, we derived approximately 58% of our revenues from sales to ComEd and PECO, as a result of these agreements.

Our supply agreements with ComEd and PECO are expected to provide us with a stable source of revenue; they do not, however, provide us with any guaranteed level of customer sales. As long as we have commitments to ComEd and PECO, our revenues will largely be a function of the cost of fulfilling these obligations and how much electricity is available to sell in wholesale markets after fulfilling those contracts. Generally, to the extent market prices decrease, customers may have an incentive to obtain electricity from alternative energy suppliers. To the extent that customers choose alternative energy suppliers, our revenues from contracts with ComEd and PECO will be reduced and our revenues will depend more on prices in the wholesale markets. If market prices increase substantially and our load requirements exceed our generation capacity, we may be required to purchase expensive power in the wholesale markets. Thus, any dramatic change in electricity prices combined with switching by ComEd's and PECO's customers could have an adverse effect on our

results of operations or financial condition. Similarly, if we lose a substantial portion of these load requirements, we may be required to sell excess energy into the wholesale market at lower prices.

Further, while our contracts with ComEd and PECO are currently a substantial portion of our business, we cannot predict whether they will be renewed at the end of their respective terms or, if renewed, what the terms of such renewal would be.

After we have met our contractual commitments, we sell energy in the wholesale markets. These sales expose us to the risks of rising and falling prices in those markets, and cash flows may vary accordingly. After our contracts with ComEd and PECO expire, our cash flows will largely be determined by our ability to successfully market energy, capacity and ancillary services and by wholesale prices of electricity.

The marketing, trading and risk management activities of our Power Team may not be successful.

The principal function of Power Team is to manage our long asset-based position in the markets for energy and capacity. Power Team's risk management and other activities may not yield the planned or expected results. As a consequence, we are exposed to the risks of the commodity market for electricity that can exhibit extremely high volatility.

In addition, we are exposed to the risk that a counterparty with whom we transact business does not perform its obligations or does not pay us. While we employ a rigorous counterparty credit evaluation methodology, the failure of one of our counterparties to perform its obligations could have a material adverse effect on our results of operations or financial condition.

We may incur substantial cost and liabilities due to our ownership and operation of nuclear facilities.

The ownership and operation of nuclear facilities involve certain risks. These risks include: mechanical or structural problems; inadequacy or lapses in maintenance protocols; the impairment of reactor operation and safety systems due to human error; the costs of storage, handling and disposal of nuclear materials; limitations on the amounts and types of insurance coverage commercially available; and uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives. The following are among the more significant of these risks:

We have invested in a significant amount of long-term transmission reservations throughout the United States. Our performance depends on our ability to retain these rights in the face of decreasing availability of transmission and rising cost for renewals of existing rights. Additionally, our performance could be impacted by changes to existing usage rules.

Our investment, acquisition and development activities may not be successful.

We currently intend to grow our generation portfolio through investments, acquisitions and the development of new energy projects, the completion of any of which is subject to substantial risk. The competitive energy market is emerging following deregulation and we may not be successful in anticipating appropriate market opportunities. It is possible that, due to a variety of factors, including purchase price, operating performance and future market conditions, we would be unable to achieve our goals. We may not be able to successfully integrate our acquisitions or investments with our existing businesses. Successful acquisition and development are contingent upon, among other things, negotiation of contracts satisfactory to us with other project participants and receipt of required governmental approvals and consents. Successful development of new projects depends on our ability to obtain permits and equipment and complete the projects within budget in a timely fashion. Further, we may be unable to obtain the substantial debt and equity capital required to invest in, acquire and develop new generation projects, to refinance existing projects or to complete projects under construction.

Our business may be adversely affected by regulatory changes in the electric power industry.

The regulation of the electric power industry continues to undergo substantial changes at both the state and Federal level. These changes have significantly affected the industry and the manner in which its participants conduct their businesses.

Future changes in laws and regulations, including changes resulting from increased security concerns, may have an effect on our business in ways that we cannot predict. Some restructured markets have recently experienced supply problems and price volatility that have been the subject of a significant amount of media coverage, much of which has been critical of the restructuring initiatives. In some of these markets, including California, government agencies and other interested parties have made proposals to re-regulate portions of the utility industry that have previously been deregulated and, in California, legislation has been passed placing a moratorium on the sale of generation plants by regulated utilities. Other proposals to re-regulate our industry may be made, and legislative or other attention to the electric power restructuring process may cause the process to be delayed, discontinued or reversed in the states in which we currently, or may in the future, operate. If competition in the electric power industry is discontinued, or our business re-regulated, we cannot predict the impact on our business.

We may not be able to respond effectively to competition or new technologies.

We may not be able to respond in a timely or effective manner to the many changes in the power industry that may occur as a result of regulatory initiatives to increase competition. As a result, additional competitors in our industry may be created, and we may not be able to maintain our revenues and earnings levels or pursue our growth strategy. In addition, new technologies may be developed that impact the competitiveness of our generation facilities. To the extent that competition increases, our profit margins may be negatively affected.

While demand for electricity is generally increasing throughout the United States, the rate of construction and development of new, more efficient, electric generation facilities may exceed increases in demand in some regional electric markets. The introduction of new participants with better

technologies in our regional markets could increase competition, which could lower prices and have a material adverse effect on our results of operations or financial condition.

We have operated as a separate, stand-alone entity since January 1, 2001. We depend on Exelon for some of our liquidity, capital resource and credit support needs, and on our affiliates for certain general corporate and other services. We are still in the process of integrating the generation assets and operations we acquired from ComEd and PECO. Additionally, we may not be able to successfully integrate our acquisitions or developments with our existing business.

Our sole limited liability company member, Exelon Ventures Company, LLC, is controlled by Exelon and, therefore, ultimately Exelon controls the decision of all matters submitted for member approval and has control over our management and affairs. In circumstances involving a conflict of interest between Exelon, on the one hand, and our creditors, on the other, Exelon could exercise its power to control us in a manner that would benefit Exelon to the detriment of our creditors, including the holders of the exchange notes.

We rely on sales to our affiliates, ComEd and PECO, under long-term contracts for a majority of our revenues. Conflicts of interest may arise if we need to enforce the terms of agreements between us and ComEd and PECO. Decisions concerning the interpretation or operation of these agreements could be made from perspectives other than the interests solely of our company or its creditors, including the holders of the exchange notes.

We are subject to regulation by the SEC under the Public Utility Holding Company Act.

We are subject to regulation by the SEC under the Public Utility Holding Company Act of 1935. Under PUHCA, we cannot issue debt or equity securities or guaranties without the SEC's prior approval. Under the Public Utility Holding Company Act (PUHCA), generally, we can invest only in traditional electric and gas utility businesses and related businesses. The acquisition of the voting stock of other gas or electric utilities is subject to prior SEC approval. PUHCA also imposes restrictions on transactions among affiliates. The restrictions imposed on us by PUHCA may limit our ability to pursue acquisition or development opportunities.

Following the completion of this exchange offer, the exchange notes will be freely tradable by most holders. See "The Exchange Offer." We do not intend to list the exchange notes on any United States or foreign securities exchange. We can give no assurances concerning the liquidity of any market that may develop for the exchange notes, the ability of any investor to sell the exchange notes, or the price at which investors would be able to sell their exchange notes. If a market for the exchange notes does not develop, investors may be unable to resell the exchange notes for an extended period of time, if at all. Consequently, investors may not be able to liquidate their investment readily, and lenders may not readily accept the exchange notes as collateral for loans.

If you fail to exchange the original notes, they will remain subject to transfer restrictions.

Any original notes that remain outstanding after this exchange offer will continue to be subject to restrictions on their transfer. After this exchange offer, holders of original notes will not (with limited exceptions) have any further rights under the exchange and registration rights agreement. Any market

for original notes that are not exchanged could be adversely affected by the conclusion of this exchange offer.

Late deliveries of the original notes and other required documents could prevent a holder from exchanging its notes.

Holders are responsible for complying with all exchange offer procedures. Issuance of exchange notes in exchange for original notes will only occur upon completion of the procedures described in this prospectus under the heading "The Exchange Offer—Procedures for Tendering Original Notes." Therefore, holders of original notes who wish to exchange them for exchange notes should allow sufficient time for completion of the exchange procedure. We are not obligated to notify you of any failure to follow the proper procedure.

If you are a broker-dealer, your ability to transfer the notes may be restricted.

A broker-dealer that purchased original notes for its own account as part of market-making or trading activities must deliver a prospectus when it sells the exchange notes. Our obligation to make this prospectus available to broker-dealers is limited. Consequently, we cannot guarantee that a proper prospectus will be available to broker-dealers wishing to resell their exchange notes.

This prospectus includes "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this prospectus that address activities, events or developments that we expect or anticipate will or may occur in the future, including such matters as our projections, future capital expenditures, business strategy, competitive strengths, goals, expansion, market and industry developments and the growth of our businesses and operations, are forward-looking statements. These statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. These statements involve a number of risks and uncertainties, many of which are beyond our control. The following are among the most important factors that could cause actual results to differ materially from the forward-looking statements.

Consequently, all of the forward-looking statements made in this prospectus are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by us will be realized or, even if realized, will have the expected consequences to or effects on us or our business prospects, financial condition or results of operations. You should not place undue reliance on these forward-looking statements in making your investment decision. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to these forward-looking statements to reflect events or circumstances that occur or arise or are anticipated to occur or arise after the date hereof. In making an investment decision regarding the exchange notes, we are not making, and you should not infer, any representation about the likely existence of any particular future set of facts or circumstances.

The exchange offer is being made in accordance with requirements of the registration rights agreement. We will not receive any cash proceeds from the issuance of the exchange notes in the exchange offer. In exchange for issuing the exchange notes as described in this prospectus, we will receive an equal principal amount of original notes, which will be canceled.

The net proceeds from the sale of the original notes were used to repay intercompany obligations of $696 million to Exelon incurred to fund the acquisition of our interest in Sithe. The intercompany obligation to Exelon was a demand note that carried interest at a floating rate and was due no later than December 16, 2001.

The following table sets forth our selected historical consolidated financial data. The historical consolidated income statement data for the years ended December 31, 2001, December 31, 2000 and December 31, 1999 have been derived from our audited financial statements included elsewhere in this prospectus. The historical consolidated balance sheet data as of December 31, 2001 and 2000 have been derived from our audited financial statements included elsewhere in this prospectus. The historical consolidated balance sheet data as of December 31, 1999 has been derived from our unaudited financial statements. The information set forth below should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) and the Consolidated Financial Statements and accompanying Notes to Consolidated Financial Statements included elsewhere in this prospectus. Our results of operations for the year ended December 31, 1999 and for the period from January 1, 2000 to October 19, 2000 are the results of operations of the generation business unit of PECO. After October 20, 2000, the date of the merger, our results are the results of the PECO generation business unit and the ComEd business unit combined. Since January 1, 2001, we have operated as a separate generation company.

	For The Years Ended At December 31,
	2001	2000	1999
Balance Sheet Data
Property, Plant and Equipment, net	1,160	831	719
Nuclear Fuel, net	843	896	271
Total Assets	8,242	8,262	2,292
Current Liabilities	1,073	2,176	404
Long-Term Debt	1,021	205	209
Total Non-Current Liabilities	3,212	3,271	729
Member's Equity	2,936	2,610	950

	For The Years Ended At December 31,
	2001		2000		1999
Other Data
EBITDA(1)	1,636		736		600
Ratio of Earnings to Fixed Charges(2)	6.15		9.45		14.46
Capital Expenditures	851		326		348
Cash Flows from Operating Activities	1,331		476		429
Cash Flows from Investing Activities	(1,110	)	(1,164	)	(431	)
Cash Flows from Financing Activities	(1	)	692		2

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

Net Income. Our net income increased $264 million, or 102%, for 2001. Income before cumulative effect of changes in accounting principles increased $252 million, or 97%, for 2001.

Earnings Before Interest and Income Taxes. We and our parent Exelon evaluate our performance based on earnings before interest and income taxes (EBIT). In addition to components of operating income as shown on the consolidated statements of income, EBIT includes equity in earnings of unconsolidated affiliates, and other income and expense recorded in other, net, with the exception of investment income.

The October 20, 2000 merger of PECO and Unicom, and the January 1, 2001 corporate restructuring, significantly impacted our results of operations. To provide a more meaningful analysis of results of operations, the EBIT analyses below identifies the portion of the EBIT variance that is attributable to the former ComEd generation business unit results of operations and the portion of the variance that results from normal operations attributable to changes in components of our underlying operations. The merger variance represents the former ComEd generation business unit results for the year ended December 31, 2000 prior to the October 20, 2000 acquisition date as well as the effect of merger-related costs incurred in 2000. The 2000 effects of the merger and restructuring were developed using estimates of various items, including allocation of corporate overheads and intercompany transactions.

Our EBIT increased $515 million for 2001 compared to 2000. This increase was primarily attributable to higher margins on increased market and affiliate wholesale energy sales, coupled with reduced operating expenses at the nuclear plants, partially offset by additional depreciation and decommissioning expense. During the first five months of 2001, we benefited from increases in wholesale market prices, particularly in the Pennsylvania-New Jersey-Maryland control area and Mid-America Interconnected Network regions. The increase in wholesale market prices was primarily driven by significant increases in fossil fuel prices. The large concentration of nuclear generation in our portfolio allowed us to capture the higher prices in the wholesale market for sales to non-affiliates with minimal increase in fuel prices. Our revenues for 2001 include charges to affiliates for line losses. Line loss charges were not included in 2000 revenue. We also benefited from higher nuclear plant output due to increased capacity factors during 2001. Energy marketing activities positively impacted 2001 results. Mark-to-market gains were $16 million and $14 million on non-trading and trading energy contracts, respectively, offset by realized trading losses of $6 million.

Our sales were 201,879 GWhs in 2001 compared to 200,072 GWhs in 2000, approximately 60% of which were to affiliates. Supply sources for 2001 and 2000 were as follows:

	2001		2000
Operated nuclear units	54	%	54	%
Purchases	37	%	37	%
Fossil and hydro units	3	%	3	%
Generation investments	6	%	6	%
Total	100	%	100	%

Our nuclear fleet, including AmerGen, performed at a weighted average capacity factor of 94.4% for 2001 compared to 93.8% in 2000. Our nuclear fleet's production costs, including AmerGen, were $12.79 per MWh for 2001, compared to $14.65 per MWh for 2000. Our purchased power costs were $42.26 MWh for 2001, compared to $38.05 per MWh for 2000. The increase resulted from the increase in fuel prices in the first quarter of 2001 as well as the increase in volumes sold during peak demand in 2001 compared to 2000.

Operating expenses were favorably affected by reductions in labor costs due to a decline in the number of employees and fewer nuclear outages in 2001 than in 2000, which offset the effect of increases in litigation-related expenses of $30 million. In addition, our EBIT benefited from an increase in equity in earnings of AmerGen and Sithe of $86 million in 2001 compared to the prior-year period reflecting a full year of operations for Sithe and AmerGen's Oyster Creek plant in 2001.

The increase in depreciation and decommissioning expense is primarily due to an increase in decommissioning expense of $140 million resulting from the discontinuance of regulatory accounting practices associated with decommissioning costs for the former ComEd nuclear generating stations that are in active generation, partially offset by a $90 million reduction in depreciation and decommissioning expense attributable to the extension of estimated service lives of our generating plants.

Interest Expense. Interest expense increased $74 million in 2001, from $41 million, in 2000. This increase was primarily attributable to increased interest charge on the note payable to Exelon of $23 million, interest charges of $26 million due to the issuance of $700 million of 6.95% senior unsecured notes in a 144A offering in June 2001, $23 million of additional interest due to a full year of interest charges on the spent fuel obligation compared to only two months in 2000 for the former ComEd generating stations and $15 million of interest charges from affiliates. These increases were partially offset by capitalized interest of approximately $17 million.

Investment Income. Investment income is recorded in Other, Net on the Consolidated Statements of Income, but is excluded from EBIT. Investment income decreased by $29 million due to net realized losses of $127 million offset by interest and dividend income of $67 million on the nuclear decommissioning trust funds reflecting the discontinuance of regulatory accounting practices associated with nuclear decommissioning costs for the nuclear stations formerly owned by ComEd, primarily offset by increased income of $31 million of money market interest and interest on the loan to Sithe recorded in 2001.

Income Taxes. The effective income tax rate was 39.0% for 2001 as compared to 38.1% for 2000. The increase in the effective income tax rate was primarily attributable to a higher effective state income rate due to operations in Illinois subsequent to the merger and a reduction in the investment tax credit. Income taxes increased by $167 million in 2001 as compared to 2000, $160 million of which is due to higher pretax income and $7 million due to a higher effective income tax rate.

On January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), as amended, resulting in a benefit of $12 million, net of income taxes.

Earnings Before Interest and Income Taxes. To provide a more meaningful analysis of our results of operations, the EBIT analysis below identifies the portion of the EBIT variance that is attributable to the former ComEd generation business unit results of operations and the portion of the variance that results from normal operations attributable to changes in components of our underlying operations. The merger variance represents the former ComEd generation business unit results for the period after October 20, 2000 as well as the effect of merger-related costs incurred in 2000. The 2000 and 1999 results also reflect the corporate restructuring as if it had occurred on January 1, 1999. The 2000 effects of the merger and restructuring were developed using estimates of various items, including allocation of corporate overheads and intercompany transactions.

Our EBIT increased $117 million for 2000 compared to 1999. The merger accounted for $71 million of the variance. The remaining $46 million increase resulted primarily from higher margins on market and affiliate wholesale energy sales, a charge against earnings of $15 million related to the abandonment of two information systems implementations in 1999 and a $15 million write-off in 1999 of the investment in a cogeneration facility in connection with the settlement of litigation. Our EBIT benefited from an increase in equity in earnings of AmerGen of $4 million in 2000 compared to the prior-year period. Effective with the acquisition of Clinton Nuclear Power Station by AmerGen, our agreement to manage Clinton was terminated, resulting in lower revenues of $99 million and lower operating and maintenance expense of $70 million.

Our nuclear fleet, including AmerGen, performed at a weighted average capacity factor of 93.8% for 2000. Our nuclear fleet production costs for 2000, including AmerGen, were $14.65 per MWh. Our purchased power costs for 2000 were $38.05 per MWh.

Interest Expense. Interest expense increased $29 million, or 242%, to $41 million in 2000. The increase was primarily attributable to interest related to the spent fuel obligation of the former ComEd nuclear plants, which was assumed in connection with the merger, and interest expense related to the $696 million note payable to Exelon used to finance our investment in Sithe.

Income Taxes. The effective tax rate was 38.10% in 2000 as compared to 38.0% in 1999.

Our capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financings and borrowings or capital contributions from Exelon. Our access to external financing at reasonable terms is dependent on our credit ratings and our general business condition, as well as the general business conditions of the industry. Our business is capital intensive. Capital resources are used primarily to fund our capital requirements, including construction, investments in new and existing ventures, and repayments of maturing debt. Any potential future acquisitions could require external financing or borrowings or capital contributions for Exelon.

Cash Flows from Operating Activities. Cash flows provided by operations for 2001 were $1.3 billion. Our cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including our affiliated companies. Our future cash flow from operating activities will depend upon future demand and market prices for energy and the ability to continue to produce and supply power at competitive costs.

Cash Flows from Investing Activities. Cash flows used in investing activities for 2001 were $1.1 billion, primarily for capital expenditures of $515 million, investment in nuclear fuel of $336 million and $239 million related to our investment in the nuclear decommissioning funds. We project capital expenditures of approximately $1.1 billion in 2002, approximately 75% of which are for additions to and upgrades of existing facilities, nuclear fuel and increases in capacity at existing plants. Capital expenditures are projected to increase in 2002 as compared to 2001 due to higher nuclear fuel expenditures, growth and an increase in the number of planned refueling outages, during which significant maintenance work is performed. Eleven nuclear refueling outages, including AmerGen, are planned for 2002, compared to six during 2001. Total capital expenditures during nuclear refueling outages are expected to increase in 2002 over 2001 by $24 million. We anticipate that our capital expenditures will be funded by internally generated funds, external borrowings, and borrowings or capital contributions from Exelon. Our proposed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

In addition to the 2002 capital expenditures of $1.1 billion, we expect to close the purchase of two natural-gas and oil-fired plants from TXU Corp. (TXU) in the second quarter of 2002. The $443 million purchase is expected to be funded with available cash and borrowings from Exelon.

During 2001, we loaned Sithe $150 million, which was repaid by Sithe in December of 2001. During 2001, Sithe paid us $2 million in interest on the loan.

Cash Flows from Financing Activities. Cash flows used in financing activities were $1 million in 2001 primarily attributable to the issuance of $700 million of senior unsecured notes with a maturity of June 2011 The majority of the proceeds of this issuance were used to repay Exelon for amounts borrowed to finance our investment in Sithe. We also issued $121 million of pollution control bonds to refinance an equivalent amount originally issued by PECO.

Credit Issues. We meet short-term liquidity requirements primarily through internally generated cash or borrowings from Exelon. We, along with ComEd, PECO and Exelon, entered into a $1.5 billion unsecured revolving credit facility with a group of banks. We currently cannot borrow under the credit agreement until we deliver audited financial statements to the banks, which is expected to occur in the second quarter of 2002. At December 31, 2001, we had outstanding $700 million of 6.95% senior unsecured debt, $317 million of variable rate pollution control notes and other long-term notes payable of $9 million. For 2001, the average interest rate on these pollution control notes was approximately 2.62% Certain of the credit agreements to which we are party require us to maintain a debt to total capitalization ratio of 65% or less. At December 31, 2001, our debt to total capitalization ratio on that basis was 35%.

Our access to the capital markets and financing costs in those markets is dependent on our securities ratings. None of our borrowings are subject to default or prepayment as a result of a downgrading of securities ratings, although such a downgrading could increase interest charges under the bank credit facility. We enter agreements to purchase energy and capacity, including obligations that are treated as derivatives, which require us to maintain investment grade ratings. Failure to maintain investment grade ratings would allow a counterparty to terminate its contract and settle the transaction on a net present value basis. Exelon has provided guarantees to support certain of our lines of credit, surety bonds, nuclear insurance and energy marketing contracts.

Exelon has obtained an order from the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA) authorizing financing transactions, including the issuance of common stock, preferred securities, long-term debt and short-term debt in an aggregate amount not to exceed $4 billion. The order applies to our issuances as well. As of December 31, 2001, $3.0 billion of financing authority was available under the SEC order. Exelon requested, and the SEC reserved jurisdiction over, an additional $4 billion in financing authorization. Exelon agreed to limit its short-term debt outstanding to $3 billion of the $4 billion total financing authority. Exelon has asked the SEC to eliminate the short-term debt restriction. The SEC order also authorized Exelon to issue guarantees of up to $4.5 billion outstanding at any one time. At December 31, 2001, Exelon had provided $1.4 billion of guarantees. Under PUHCA and the Federal Power Act, we can pay dividends only from retained or current earnings. At December 31, 2001, we had retained earnings of $524 million. Exelon is also limited by order of the SEC under PUHCA to an aggregate investment of $4 billion in exempt wholesale generators (EWGs) and foreign utility companies (FUCOs). Exelon requested, and the SEC reserved jurisdiction over, an additional $1.5 billion investment in EWGs and FUCOs.

Contractual Obligations and Commercial Commitments. Our contractual obligations and commercial commitments as of December 31, 2001 are as follows:

We have an obligation to decommission our nuclear power plants. Our current estimate of decommissioning costs for our owned nuclear plants is $7.2 billion in current-year (2002) dollars. Nuclear decommissioning activity occurs primarily after a plant's retirement and is currently estimated to begin in 2029, except for the retired Zion station, which is currently estimated to begin decommissioning in 2013. Decommissioning costs are recoverable by ComEd and PECO through regulated rates and are remitted to us for deposit in the decommissioning trust funds. In 2001, ComEd and PECO collected from customers and remitted to us approximately $102 million in decommissioning costs. At December 31, 2001, the decommissioning liability, which is recorded over the life of the plant, recorded in Property, Plant and Equipment, Net as well as Deferred Credits and Other Liabilities on our balance sheet was $2.7 billion and $1.3 billion, respectively. In order to fund future decommissioning costs, we held $3.2 billion of investments in nuclear decommissioning trust funds, which are included as Deferred Debits and Other Assets on our balance sheet and which include net unrealized and realized gains. Due to the performance of the United States debt and equity markets in 2001, the value of assets held in trusts to satisfy the obligations of the nuclear generating stations eventual decommissioning has decreased. Contributions to the nuclear decommissioning trust funds of $112 million offset net losses of $109 million, resulting in a 2% increase in the decommissioning trust funds balance at December 31, 2001 compared to December 31, 2000. We believe that the amounts being remitted to us by ComEd and PECO and the earnings on nuclear decommissioning trust funds will be sufficient to fully fund our decommissioning obligations.

Off Balance Sheet Obligations. Beginning December 18, 2002, we will have the right to purchase all (but not less than all) of the remaining outstanding shares of the Sithe common stock. The option expires on December 18, 2005. In addition, each of Sithe's other stockholder groups will have the right to require us to purchase all (but not less than all) of its shares during the same period in which we can exercise our option. At the end of that period, if no stockholder has exercised its option, we will have a one-time option to purchase shares from the other stockholders to bring our holdings to 50.1% of the total outstanding shares. If we exercise our option or if all the stockholder groups exercise their put rights, the purchase price for 70% of the remaining 50.1% of the Sithe stock will be set at a fair market value plus a 10% premium in the case of a call or 10% discount in the case of a put, subject to a floor of $430 million and a ceiling of $650 million, and the remaining portion will be valued at fair market value subject to floor price of $141 million and a ceiling price of $330 million, plus, in each case, interest accrued from the beginning of the exercise period.

If we increase our ownership in Sithe to 50.1% or more, Sithe will become a consolidated subsidiary and our financial results will include Sithe's financial results from the date of purchase. At December 31, 2001, Sithe had total assets of $4.2 billion and long-term debt of $2.3 billion, including $2.1 billion of non-recourse project debt and excluding $107 million of non-recourse project debt associated with Sithe's equity investments. For the year ended December 31, 2001 Sithe had revenues of $1 billion. As of December 31, 2001, we had a $725 million equity investment in Sithe.

Additionally, the debt on the books of our unconsolidated equity investments and joint ventures is not reflected on our Consolidated Balance Sheets. Total investee debt, including the debt of Sithe described in the preceding paragraph, is currently estimated to be $2.4 billion ($1.2 billion based on Exelon Generation's ownership interest of the investments).

We and British Energy, our joint venture partner in AmerGen, have each agreed to provide up to $100 million to AmerGen at any time for operating expenses. We have committed to provide AmerGen with capital contributions equivalent to 50% of the purchase price of any acquisitions AmerGen makes in 2002.

We are exposed to market risks associated with commodity price, credit, interest rates and equity prices. The inherent risk in market sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, counterparty credit, interest rates and equity security prices. Exelon's corporate Risk Management Committee (RMC) sets forth risk management philosophy and objectives through a corporate policy, and establishes procedures for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of derivative activity and risk exposures. The RMC is chaired by Exelon's chief risk officer and includes the chief financial officer, general counsel, treasurer, vice president of corporate planning and officers from each of the Exelon business units. The RMC reports to the Exelon Board of Directors on the scope of our derivative and risk management activities.

Commodity Price Risk. Commodity price risk is associated with market price movements resulting from excess or insufficient generation, changes in fuel costs, market liquidity and locational price commodity differences. Trading activities and non-trading marketing activities include the purchase and sale of electric capacity and energy and fossil fuels, including oil, gas and coal. The availability and prices of energy and energy-related commodities are subject to fluctuations due to factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies and other events.

Marketing (non-trading) activities. To the extent that our generation supply (either owned or contracted) is in excess of our obligations to customers, including ComEd's and PECO's retail load, the available electricity is sold in the wholesale markets. To reduce price risk caused by market fluctuations, we enter into derivative contracts, including forwards, futures, swaps, and options with approved counterparties, to hedge our anticipated exposures. Market price risk exposure is the risk of a change in the value of unhedged positions. We expect to maintain a minimum 80% hedge ratio in 2002 for our energy marketing portfolio. This hedge ratio represents the percentage of our forecasted aggregate annual generation supply that is committed to firm sales, including sales to our affiliated entities. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand and volatility. Absent any opportunistic efforts to mitigate market price exposure, the estimated market price exposure for the non-trading portfolio associated with a 10% reduction in the average around-the-clock market price of electricity is an approximate $100 million decrease in net income. This sensitivity assumes an 80% hedge ratio and that price changes occur evenly throughout the year and across all markets. The sensitivity also assumes a static portfolio. We expect to actively manage our portfolio to mitigate the market price exposure. Actual results could differ depending on the specific timing of, and markets affected by, the price changes, as well as future changes in our portfolio.

Trading activities. We began to use financial contracts for trading purposes in the second quarter of 2001. The trading activities were entered into as a complement to our energy marketing portfolio and represent a very limited portion of our overall energy marketing activities. For example, the limit on open positions in electricity for any forward month represents less than 5% of the owned and contracted supply of electricity. The trading portfolio is planned to grow modestly in 2002, subject to stringent risk management limits and policies, including volume, stop-loss and value-at-risk limits to manage exposure to market risk. A value-at-risk (VAR) model is used to assess the market risk associated with financial derivative instruments entered into for trading purposes. VAR represents the potential gains or losses for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. The measured VAR as of December 31, 2001, using a Monte Carlo model with a 95% confidence level and assuming a one-day time horizon was approximately $800,000. The measured VAR represents an estimate of the potential change in value of our portfolio of trading related financial derivative instruments. These estimates, however, are not necessarily indicative of

actual results, which may differ due to the fact that actual market rate fluctuations may differ from forecasted fluctuations and due to the fact that the portfolio may change over the holding period.

Our energy contracts are accounted for under SFAS No. 133. Most non-trading contracts qualify for a normal purchases and normal sales exception under that accounting pronouncement and therefore are not recorded on the balance sheet and marked to market. Contracts that do not qualify for the exception are recorded as assets or liabilities on the balance sheet at fair value. Changes in the fair value of qualifying hedge contracts are recorded in Other Comprehensive Income, and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS No. 133 or the ineffective portion of hedge contracts is recognized in earnings on a current basis. Outlined below is a summary of the changes in fair value for those contracts included as assets and liabilities in our balance sheet for the year ended December 31, 2001:

The total change in fair value during 2001 is reflected in the 2001 consolidated financial statements as follows:

The majority of our contracts are non-exchange traded contracts valued using prices provided by external sources, which primarily represent price quotations available through brokers or over-the-counter, on-line exchanges. Prices reflect the average of the bid-ask midpoint prices obtained from all sources that we believe provide the most liquid market for the commodity. The terms for which such price information is available varies by commodity, by region and by product. The remainder of the assets represents contracts for which external valuations are not available, primarily option contracts. These contracts are valued using the Black model, an industry standard option valuation model and other valuation techniques. The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2001 and may change as a result of future

changes in these factors. The maturities of the net energy trading and non-trading assets and sources of fair value as of December 31, 2001 are as follows:

Management uses its best estimates to determine the fair value of commodity and derivative contracts it holds and sells. These estimates consider various factors, including closing exchange and over-the-counter price quotations, time value, volatility factors, and credit exposure. However, it is possible that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities, and such variations could be material.

Credit Risk. We have credit risk associated with counterparty performance, which includes, but is not limited to, the risk of financial default or slow payment. Counterparty credit risk is managed through established policies, including establishing counterparty credit limits, and in some cases requiring deposits or letters of credit to be posted by certain counterparties. Our counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. We have entered into master netting agreements with the majority of our large counterparties, which reduce exposure to risk by providing for the offset of amounts payable to the counterparty against the counterparty receivables.

We participate in the five established, real-time energy markets, which are administered by independent system operators (ISOs): Pennsylvania, New Jersey, Maryland, LLC (PJM), which is in the Mid-Atlantic Area Council region; New England and New York, which are both in the Northeast Power Coordinating Council region; California, which is in the Western Systems Coordinating Council region; and Texas, which is administered by the Electric Reliability Council of Texas. In 2001, approximately one-half of our transactions, on a megawatthour basis, were made in these markets. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot markets which are operated by the ISOs For sales into the spot markets administered by an ISO, the ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the ISOs may under certain circumstances require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty, could result in a material adverse impact on our financial condition, results of operations or net cash flows.

In areas where there is no spot market, electricity is purchased and sold solely through bilateral agreements.

Interest Rate Risk. We use a combination of fixed-rate and variable-rate debt to reduce interest rate exposure. Interest rate swaps may be used to adjust exposure when deemed appropriate based

upon market conditions. We also use forward-starting interest rate swaps and treasury rate locks to lock in interest rate levels in anticipation of future financings. These strategies are employed to maintain the lowest cost of capital. As of December 31, 2001, a hypothetical 10% increase in the interest rates associated with pollution control bonds would result in an approximately $1 million decrease in pre-tax earnings for 2002.

Equity Price Risk. We maintain trust funds, as required by the Nuclear Regulatory Commission (NRC), to fund certain costs of decommissioning our nuclear plants. As of December 31, 2001, these funds are reflected at fair value on our balance sheet. The mix of securities is designed to provide returns to be used to fund decommissioning and to compensate, including inflationary increases in decommissioning costs. However, the equity securities in the trusts are exposed to price fluctuations in equity markets, and the value of fixed rate, fixed income securities are exposed to changes in interest rates. We actively monitor the investment performance and periodically review asset allocation in accordance with our nuclear decommissioning trust fund investment guidelines. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $204 million reduction in the fair value of the trust assets.

The preparation of financial statements in conformity with Generally Accepted Accounting Principles requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. The following areas represent those that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain.

Accounting for Derivative Instruments. We use derivative financial instruments primarily to manage our commodity price and interest rate risks. Derivative financial instruments are accounted for under SFAS No. 133. Accounting for derivatives continues to evolve through guidance issued by the Derivatives Implementation Group (DIG) of the Financial Accounting Standards Board. To the extent that changes by the DIG modify current guidance, including the normal purchases and normal sales determination, the accounting treatment for derivatives may change.

Energy Contracts. To manage our use of generation supply (including owned and contracted assets), we enter into contracts to purchase or sell electricity, fossil fuels, and ancillary products such as transmission rights and congestion credits, and emission allowances. These energy marketing contracts are considered derivatives under SFAS 133 unless a determination is made that they qualify for a SFAS No. 133 normal purchases and normal sales exclusion. If the exclusion applies, those contracts are not marked-to-market and are not reflected in the financial statements until delivery occurs.

The availability of the normal purchases and normal sales exclusion to specific contracts is based on a determination that excess generation is available for a forward sale and similarly a determination that at certain times generation supply will be insufficient to serve load. This determination is based on internal models that forecast customer demand and generation supply. The models include assumptions regarding customer load growth rates, which are influenced by the economy, weather and the impact of customer choice, and generating unit availability, particularly nuclear generating unit capability factors. The critical assumptions used in the determination of normal purchases and normal sales are consistent with assumptions used in the general corporate planning process.

Energy contracts that are considered derivatives may be eligible for designation as hedges. If a contract is designated as a hedge, the change in its market value is generally deferred as a component of other comprehensive income until the transaction it is hedging occurs. Conversely, the change in the market value of derivatives not designated as hedges is recorded in current period earnings. To qualify

as a cash flow hedge, the fair value changes in the derivative must be expected to offset 80%-120% of the change in fair value or cash flows of the hedged item. The effectiveness of an energy contract designated as a hedge is determined by internal models that measure the statistical correlation between the derivative and the associated hedged item.

When external quoted market prices are not available, we use the Black model, a standard industry valuation model to determine the fair value of energy derivative contracts. The valuation model uses volatility assumptions relating to future energy prices based on specific energy markets and utilizes externally available forward market price curves.

Interest Rate Derivatives. We use derivatives to manage our exposure to fluctuation in interest rates and planned future debt issuances. Hedge accounting has been used for all interest rate derivatives to date based on the probability of the transaction and the expected highly effective nature of the hedging relationship between the interest rate swap contract and the interest payment or changes in fair value of the hedged debt. Dealer quotes are available for all of our interest rate swap agreement derivatives.

Nuclear Decommissioning. Our current estimate of our nuclear facilities' decommissioning cost is $7.2 billion in current year dollars. Calculating this estimate involves significant assumptions with respect to the expected increases in decommissioning costs relative to general inflation rates, changes in the regulatory environment or regulatory requirements, and the timing of decommissioning. The estimated service life of a nuclear station is also a significant assumption because decommissioning costs are generally recognized over the life of the generating station. Cost estimates for decommissioning our nuclear facilities have been prepared by an independent engineering firm and reflect currently existing regulatory requirements and available technology. Nuclear station service lives, over which the decommissioning costs are recognized, were extended by 20 years in 2001. The life extension is subject to NRC approval of an extension of existing NRC operating licenses, which generally are 40 years. As discussed in New Accounting Pronouncements, this accounting will be affected by the adoption of SFAS No. 143, "Asset Retirement Obligations" (SFAS No. 143) effective January 1, 2003.

Estimated Service Lives of Property, Plant and Equipment. We depreciate our generation facilities and other property plant and equipment over estimated useful service lives. These estimated useful service lives are determined using three criteria: (1) economic feasibility, (2) physical feasibility and (3) functional feasibility. Economic feasibility is demonstrated through a cost/benefit analysis that an asset is economically viable and that the asset is providing an overall financial benefit. Physical feasibility represents the fact that the actual plant and equipment can operate during the defined period. Changes in physical feasibility may result from changes in the regulatory environment or environmental restrictions. Functional feasibility evaluates the impact of technology changes on the estimated service lives. In addition, nuclear power stations operate under licenses granted by the Nuclear Regulatory Commission (NRC). Operating licenses for our operating plants are for 40 years. We have or intend to request 20-year life extensions of these operating licenses. If not extended, nuclear plant service lives would be limited by the expiration of licenses. During 2001, we increased the estimated service lives for our operating nuclear stations, certain fossil stations and our pumped storage station. As a result of the change in service lives, depreciation and decommissioning expense decreased $90 million ($54 million, net of income taxes). Annualized savings resulting from the change will be $132 million ($79 million, net of income taxes).

Changes in the Utility Industry. The electric utility industry in the United States remains in transition. It is moving from a fully regulated industry, consisting primarily of integrated companies combining generation, transmission and distribution, to competitive wholesale generation markets with

continuing regulation of transmission and distribution. The transition has resulted in substantial disposition of generating assets by formerly integrated companies, the creation of separate and, in some cases, stand-alone generating companies and consolidation. During 2001, however, the pace of transition slowed. This slowdown was due primarily to public and governmental reactions to issues associated with deregulation efforts in California and the collapse of the wholesale electricity market in California.

At the Federal level, FERC remains committed to the development of wholesale generation markets. Although its proposal for the development of large regional transmission organizations to facilitate markets has been delayed, it is planning an initiative to standardize wholesale markets in the United States. At the state level, concerns raised by the California experiences have stalled new retail competition initiatives and slowed the separation of generation from regulated transmission and distribution assets.

We believe that the transition in the electric utility industry will continue, albeit at a slower pace than previously, particularly at the state level. This slower transition may be reflected in reduced industry consolidation in the near term and reduced disaggregation of regulated to unregulated services. These uncertainties may limit opportunities for us to pursue our plans to expand our generation portfolio.

We also believe that competition for electric generation services has created new risks and uncertainties in the industry. Some of these risks were clearly illustrated in California—the risks of inadequate sources of generation, having load obligations without owning generation, and price volatility. The situation in California also illustrated the need for additional infrastructure to support competitive markets. The uncertainties include future prices of generation services in both the wholesale and retail markets, supply and demand volatility, and changes in customer profiles that may impact margins on various electric service offerings. These uncertainties create additional risk for participants in the industry, including us, and may result in increased volatility in operating results from year to year.

Competitive Position. We compete nationally in the wholesale electric generation markets on the basis of price and service offerings, using our generation portfolio to assure customers of energy deliverability. We have agreed to supply ComEd and PECO with their load requirements for customers through 2006 and 2010, respectively. We have contracted with Exelon Energy, the competitive retail energy services subsidiary of Exelon, to meet its load requirements pursuant to its competitive retail generation sales agreements and, in addition, we have contracts to sell energy and capacity to third parties. To the extent that our resources exceed our contractual commitments, we market these resources on a short-term basis or sell them in the spot market.

Our supply agreements with ComEd and PECO are expected to provide us with a stable source of revenue; they do not, however, provide us with any guaranteed level of revenue. As long as we have commitments to ComEd and PECO, our revenues will largely be a function of the cost of fulfilling these obligations and how much electricity is available to sell in wholesale markets after fulfilling those contracts. Generally, to the extent market prices decrease, customers may have an incentive to obtain electricity from alternative energy suppliers. To the extent that customers choose alternative energy suppliers, our revenues from contracts with ComEd and PECO will be reduced and our revenues will depend more on prices in the wholesale markets. If market prices increase substantially and our load requirements exceed our generation capacity, we may be required to purchase expensive power in the wholesale markets. Thus, any dramatic change in electricity prices combined with switching by ComEd's and PECO's customers could have an adverse effect on our results of operations or financial condition. Further, while our contracts with ComEd and PECO are currently a substantial portion of our business, we cannot predict whether they will be renewed at the end of their respective terms or, if renewed, what the terms of such renewal would be.

Our future results of operations also depend upon our ability to operate our generating facilities efficiently to meet our contractual commitments and to sell energy services in the wholesale markets. A substantial portion of our generating capacity, including all of the nuclear capacity, is base-load generation designed to operate for extended periods of time at low variable costs. Nuclear generation is currently the most cost-effective way for us to meet our commitments for sales to affiliated entities and other utilities. During 2001, our nuclear generating fleet, including AmerGen, operated at a 94.4% weighted average capacity factor. The number of refueling outages, including AmerGen, is expected to increase to eleven in 2002 from six in 2001 and, accordingly, our planned nuclear capacity factor for 2002 is 91%. Failure to achieve these capacity levels may require us to contract or purchase more expensive energy in the spot market to meet these commitments. Maintenance and capital expenditures during nuclear refueling outages are expected to increase by $80 million and $24 million, respectively, in 2002 compared to 2001 as a result of the additional nuclear refueling outages. Because of our reliance on nuclear facilities, any changes in regulations by the NRC requiring additional investments or resulting in increased operating or decommissioning costs of nuclear generating units could adversely affect our results of operations.

Our wholesale marketing unit, Power Team, uses our generation portfolio, transmission rights and expertise to ensure delivery of generation to wholesale customers under long-term and short-term contracts. Power Team is responsible for supplying the load requirements of ComEd and PECO and markets the remaining energy in the wholesale markets. Power Team also buys and sells power in the wholesale markets. Trading activities were initiated in 2001 and represent a small portion of Power Team's activity. As of December 31, 2001, trading activities accounted for less than 1% of our EBIT. Trading activities are expected to increase modestly in 2002; trading activity growth will be dependent on the continued development of the wholesale energy markets and Power Team's ability to manage trading and credit risks in those markets. The spot markets also involve the credit risks of market participants purchasing energy, which we may not be able to manage or hedge. We use financial trading primarily to complement the marketing of our generation portfolio. We intend to manage the risk of these activities through a mix of long-term and short-term supply obligations and through the use of established policies, procedures and trading limits. Financial trading, together with the effects of SFAS No. 133, may cause volatility in our future results of operations.

Environmental. Our operations have in the past and may in the future require substantial capital expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, we are generally liable for the costs of remediating environmental contamination of property now owned by us or formerly owned by ComEd or PECO and of property contaminated by hazardous substances generated by us, ComEd or PECO.

As of December 31, 2001 and 2000, we had accrued $14 million and $16 million, respectively, for environmental investigation and remediation costs, other than decommissioning. We expect to spend $5 million for environmental remediation activities in 2002. We cannot predict whether we will incur other significant liabilities for any additional investigation and remediation costs at these or additional sites identified by us, environmental agencies or others, or whether such costs will be recoverable from third parties.

Security Issues and Other Impacts of Terrorist Actions. The events of September 11, 2001 have affected our operating procedures and costs and are expected to affect the cost and availability of the insurance coverages that we carry. The NRC has issued Safeguards and Threat Advisories to all nuclear power plant licensees, including us, requesting that they place their facilities on highest alert security status. In response to the NRC Advisories and on our own initiative, we also implemented enhanced security measures, such as increased guard forces, the erection of additional physical barriers, and heightened communication with authorities at all levels of government. In addition to the Advisories, the NRC began an initiative to perform a "top to bottom" review of its safeguards and security programs and requirements in light of the events of September 11.

On February 25, 2002, the NRC issued immediately effective orders modifying the operating licenses for all nuclear power plants to require all licensees, including us, to implement certain interim security enhancements. The security requirements imposed by the NRC's orders issued to us are currently estimated to increase capital expenditures by approximately $1 million per station for improvements, such as enhanced vehicle barriers, modifications to plant facilities and increased size of guard forces.

Insurance. We carry nuclear liability insurance. The Price-Anderson Act limits the liability of nuclear reactor owners for claims arising from a single incident. The current limit is $9.5 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. We carry the maximum available commercial insurance of $200 million. The remaining $9.3 billion is provided through mandatory participation in a financial protection pool. Price-Anderson is scheduled to expire on August 1, 2002. While there are numerous bills proposing to review Price-Anderson, we cannot predict at this time whether Congress will renew it or the effects on operations resulting from the expiration of the Price-Anderson Act.

In addition to nuclear liability insurance, we carry property damage and liability insurance for our properties and operations. Our property insurance through Nuclear Electric Insurance Limited (NEIL) provides coverage for damages caused by acts of terrorism at any of our nuclear generating stations. The terrorism endorsement to the NEIL policy specifies that the coverage applies to acts of terrorism similar to the September 11, 2001 events. In the event that one or more acts of terrorism cause accidental property damage within a 12-month period from the first accidental property damage under one or more policies for all insureds, the maximum recovery for all losses by all insureds will be an aggregate of $3.24 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity or any other source applicable to such losses. If total property losses exceed available funds under the policy, proportionate recovery is provided to cover a portion of an insured's property losses. The percentage recovery would be equal to the ratio of the insured's property losses and the total of all property losses.

NEIL also provides replacement power cost insurance in the event of a major accidental outage at a nuclear station. The policy provides for a waiting period before recovery of costs can commence. The premium for this coverage is subject to assessment for adverse loss experience, with a maximum assessment of $46 million per year. Recovery under this insurance for terrorist acts is subject to the $3.24 billion aggregate limit and is secondary to the property insurance described above.

We are self-insured to the extent that any losses may exceed the amount of insurance maintained. NEIL provides property and business interruption insurance for our nuclear operations. In recent years,

NEIL has made distributions to its members. Our distribution for 2001 was $69 million, which was recorded as a reduction to Operating and Maintenance Expense on our Statements of Income. Due in part to the September 11, 2001 events, we cannot predict the level of future distributions, although they are expected to be lower than historical levels.

In addition, we participate in the American Nuclear Insurers Master Worker Program, which provides coverage for worker tort claims filed for bodily injury caused by a nuclear energy accident. This program was modified, effective January 1, 1998, to provide coverage to all workers whose nuclear-related employment began on or after the commencement date of reactor operations. We will not be liable for a retrospective assessment under this new policy. However, in the event losses incurred under the small number of policies in the old program exceed accumulated reserves, a maximum retrospective assessment of up to $50 million could apply.

We do not carry any business interruption insurance other than NEIL coverage for nuclear operations. We cannot at this time predict the effect on our operations of any changes in any of these insurance policies because of terrorist acts or otherwise.

Benefit Plans. We maintain defined benefit pension plans and post-retirement welfare benefit plans. Essentially all of our employees are eligible to participate in these plans. Management employees and electing union employees, hired on or after January 1, 2001, are eligible to participate in newly established Exelon cash balance pension plans. Management employees who were active participants in the former ComEd and PECO pension plans on December 31, 2000 and remain employed by Exelon or a participating subsidiary on January 1, 2002, will have the opportunity to continue to participate in the pension plan or to transfer to the cash balance plan. Participants in the cash balance plan, unlike participants in the other defined benefit plans, may request a lump-sum cash payment upon the termination of their employment, which may result in increased cash requirements from pension plan assets. We may be required to increase future funding to the pension plan as a result of these increased cash requirements.

Due to the performance of the United States debt and equity markets in 2001, the value of assets held in trusts to satisfy the obligations of pension and postretirement benefit plans has decreased. Also, as a result of the merger and corporate restructuring, there was a larger number of employees taking advantage of retirement benefits in 2001 than in other years. These factors may also result in additional future funding requirements of the pension and postretirement benefit plans.

In 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, "Business Combinations" (SFAS No. 141), SFAS No. 142 "Goodwill and Other Intangible Assets" (SFAS No. 142, SFAS No. 143, and SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144).

SFAS No. 141 requires that all business combinations be accounted for under the purchase method of accounting and establishes criteria for the separate recognition of intangible assets acquired in business combinations. SFAS No. 141 is effective for business combinations initiated after June 30, 2001. In addition, SFAS No. 141 requires that unamortized negative goodwill related to pre-July 1, 2001 purchase be recognized as change in accounting principle concurrent with the adoption of SFAS No. 142. Included on AmerGen's balance sheet is $43 million of negative goodwill, net of accumulated amortization. Upon AmerGen's adoption of SFAS No. 141 on January 1, 2002, we will recognize our appropriate share of approximately $22 million in additional income as a cumulative effect of a change in accounting principle.

SFAS No. 142 establishes new accounting and reporting standards for goodwill and intangible assets. We adopted SFAS No. 142 as of January 1, 2002. Under SFAS No. 142, effective January 1,

2002, goodwill is no longer subject to amortization. After January 1, 2002, goodwill will be subject to an assessment for impairment using a two-step fair value based test, the first step of which must be performed at least annually, or more frequently if events or circumstances indicate that goodwill might be impaired. The first step compares the fair value of a reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step compares the carrying amount of the goodwill to the fair value of the goodwill. If the fair value of goodwill is less than the carrying amount, an impairment loss would be reported as a reduction to goodwill and a charge to operating expense, except at the transition date, when the loss would be reflected as a cumulative effect of a change in accounting principle. As of December 31, 2001, we did not have any goodwill recorded on our Consolidated Balance sheets. Accordingly, we do not expect the adoption of SFAS No. 142 to have a material impact on our financial statements.

SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. We expect to adopt SFAS No. 143 on January 1, 2003. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. Adoption of SFAS No. 143 will change the accounting for the decommissioning of our nuclear generating plants. Currently, we record the obligation for decommissioning ratably over the lives of the plants. The January 1, 2003 adoption of this standard will require a cumulative effect adjustment effective the date of adoption to adjust plant assets and decommissioning liabilities to the values they would have been had SFAS No. 143 been employed from the in-service dates of the plants.

The effect of this cumulative adjustment will be to increase the decommissioning liability to reflect a full decommissioning obligation in current year dollars. Additionally, SFAS No. 143 will require the accrual of an asset related to the full amount of the decommissioning obligation, which will be amortized over the remaining lives of the plants. The difference between the asset recognized and the liability recorded upon adoption of the standard will be charged to earnings and recognized as a cumulative effect, net of expected regulatory recovery. The decommissioning liability to be recorded represents an obligation for the future decommissioning of the plants, and as a result, interest expense will be accrued on this liability until such time as the obligation is satisfied.

We are in the process of evaluating the impact of SFAS No. 143 on our financial statements, and cannot determine the ultimate impact of adoption at this time; however, the cumulative effect could be material to our earnings. Additionally, although over the life of the plant the charges to earnings for the depreciation of the asset and the interest on the liability will be equal to the amounts currently recognized as decommissioning expense, the timing of those charges will change and in the near-term period subsequent to adoption, the depreciation of the asset and the interest on the liability could result in an increase in expense.

SFAS No. 144 establishes accounting and reporting standards for both the impairment and disposal of long-lived assets. This statement is effective for fiscal years beginning after December 15, 2001 and provisions of this statement are generally applied prospectively. We are in the process of evaluating the impact of SFAS No. 144 on our financial statements, and we do not expect the impact to be material.

We are one of the largest competitive electric generation companies in the United States, as measured by owned and controlled megawatts. We combine our large, low-cost generation fleet with an experienced wholesale power marketing operation. We directly own generation assets in the Mid-Atlantic and Midwest regions with a net capacity of 19,715 MW, including 14,250 MW of nuclear capacity. We also control another 16,245 MW of capacity in the Midwest, Southeast and South Central regions through long-term contracts.

In addition to our own generation facilities, we have acquired a 49.9% interest in Sithe Energies, Inc. with an option to purchase, beginning in December 2002, the remaining 50.1% interest. Sithe develops, owns and operates 27 generation facilities in North America. Currently, Sithe has 3,371 MW of capacity in operation and 5,051 MW under construction or in advanced development. We also own a 50% interest in AmerGen Energy Company, LLC, a joint venture with British Energy plc. AmerGen owns three nuclear stations with total generation capacity of 2,398 MW.

The following chart reflects the geographic location of our generation portfolio by North American Electric Reliability Council Region (see "—Energy Markets" below), including our long-term contracts and investments.

Our Power Team division is a major wholesale marketer of energy that uses our generation portfolio, transmission rights and expertise to ensure delivery of generation to our wholesale customers under long-term and short-term contracts. Power Team is responsible for supplying the load requirements of our utility affiliates, ComEd and PECO, and markets the remaining energy in the wholesale markets. Power Team also buys and sells power in the wholesale spot markets.

Our business strategy is to develop a national generation portfolio with fuel and dispatch diversity. To implement this strategy, we plan to:

Grow Our Generation Portfolio. We intend to continue to grow our generation portfolio through asset acquisitions, development of new plants, innovative applications of technology, joint ventures and long-term off-take contracts. Regardless of the approach employed, we remain disciplined in our evaluation of opportunities to grow our business. We use sophisticated analytical tools to evaluate the potential returns on investments as well as the risks of these investments.

Drive Cost and Operational Leadership through Proven Fleet Management and Economies of Scale. Our facilities have achieved superior performance through a proven fleet management model, an experienced management team, highly trained employees and economies of scale. Our goals are to increase fleet output and to improve efficiency, while sustaining operational safety. We intend to achieve these results in our nuclear fleet by increasing capacity factors over historic levels, reducing refueling outage duration and increasing our generation capacity through power uprates and other modifications.

In addition, we have reduced operating and maintenance costs by $93 million by capturing merger synergies, achieving economies of our fleet scale at single-unit sites, implementing planned staff reductions and reducing costs of equipment and services through consolidated purchasing programs. In addition, we expect to reduce fuel costs through both contract management and improved fuel design and management.

Finally, we intend to apply for extensions to the operating licenses for our nuclear plants. In July 2001, we applied to the NRC for extension of the Peach Bottom 2 and 3 licenses and we expect to apply for extensions of the operating licenses for Dresden 2 and 3 and Quad Cities in 2003. AmerGen is also reviewing the potential for license extensions for Oyster Creek and Three Mile Island.

Optimize the Value of Our Low-Cost Generation Portfolio through Our Power Marketing Expertise. Power Team is responsible for marketing all the energy and capacity of our owned generation facilities, long-term contracts and the three AmerGen plants. We seek to maintain a net positive supply of capacity through ownership of generation assets and power purchase agreements. In 2001, Power Team had open-market sales of 78 million MWh. In addition to supplying ComEd and PECO, Power Team markets energy, capacity and ancillary services from our owned and contracted generation.

Power Team has also contracted for access to additional generation through bilateral long-term power purchase agreements. These agreements relate to the power from specific generation plants that Power Team dispatches in a manner similar to our owned assets. We enter into power purchase agreements with the objective of obtaining low-cost energy supply sources to meet our physical delivery obligations to customers. Power Team also purchases generation from the spot markets. Power Team's operations enable us to efficiently manage the dispatch of our generation facilities with real-time market information, including energy demand levels, supply availability, market pricing, weather expectations and the anticipated timing and duration of peak demand periods.

We believe that we are well positioned to play a leading role in the competitive energy industry because of our:

Competitive, Low-Cost Fleet of Generation Assets. Our 41,362 MW fleet of generation assets makes us the largest competitive electric generation company in the United States. Our low-cost advantage is driven by our ownership of or investment in 11 nuclear generation stations, consisting of 19 units, with net capacity totaling 15,449 MW. The production costs of our nuclear fleet are significantly below the average prices of electricity in the markets where we operate. The nuclear plants benefit from stable fuel costs, minimal environmental impact from operations and a safe operating history. In addition, our fuel sources for other plants include oil, coal, gas, water and wind.

Operating Experience and Expertise. We have achieved superior operating performance in our generation business through the leadership of a deep and experienced management team. We benefit from a coordinated approach to fleet management, sharing of "best-in-class" practices across our organization and broad employee recognition that exceptional performance is required to succeed in a competitive environment. Using this experience and coordinated approach, we are increasing the capacity of our generation units through power uprates and other modifications.

Critical Mass of Generation Capacity with Economies of Scale. We believe that a limited number of substantial competitors will emerge from the consolidation and transformation of the energy industry. Our generation assets and our investments in Sithe and AmerGen provide critical mass and a leadership position in the new energy markets. As the largest generator of nuclear power in the United States, we can take advantage of our scale and scope to negotiate favorable terms for the materials and services that our business requires.

Stable Revenue Streams under Long-Term Contracts with ComEd and PECO. Under electric utility restructuring legislation in Illinois and Pennsylvania, ComEd and PECO are obligated to supply generation services to customers who do not or cannot choose an alternative energy supplier during the transition periods to a competitive supply marketplace. We have entered into long-term agreements to supply the load requirements of ComEd and PECO through 2006 and 2010, respectively. In 2001, sales to ComEd and PECO under these agreements accounted for approximately 58% of our revenues. Our contracts with ComEd and PECO, combined with our contracts to sell power in the wholesale markets, provide us with an appropriate balance in our exposure between long- and short-term commitments and wholesale market exposure.

Extensive Experience in Wholesale Power Markets. Power Team has substantial experience in energy markets, generation dispatch and the requirements for the physical delivery of power. Operating from our large asset platforms in the Mid-Atlantic and Midwest regions, Power Team has established itself as a leading asset-based power marketer. Because of our substantial asset base, Power Team has been able to distinguish itself within these regions as a reliable supplier. Currently, we are expanding our operations and generation portfolio through power purchase contracts and are also opportunistically pursuing the acquisition of generation assets nationally. With our investment in Sithe, we have established a base for future growth in New England and New York.

Type of Capacity			Capacity (MW)
Owned Generation Assets(1,2)
	Nuclear		14,250
	Fossil		3,881
	Hydro		1,584

			19,715
Long-term Contracts(3)			16,245
AmerGen and Sithe(2)			2,881

		Available Resources	38,841
Under Construction or in Advanced Development(2)			2,521

		Total Generating Resources	41,362

Our owned generation assets are primarily the nuclear generation stations in the Midwest region that we acquired from ComEd and the nuclear, fossil and hydroelectric stations in the Mid-Atlantic region that we acquired from PECO.

Our investments in generation assets consist of a 49.9% interest in Sithe and a 50% interest in AmerGen. Sithe, an independent power producer, owns and operates 27 power generation facilities in North America, with approximately 3,371 MW of net generation capacity and approximately 5,051 MW of capacity under construction or in advanced development. AmerGen owns three nuclear plants with a total capacity of 2,398 MW.

We also have access to generation capacity through contractual commitments. In particular, when ComEd sold its fossil generation assets to Midwest Generation, LLC, a subsidiary of Edison Mission Energy, ComEd entered into contracts for energy and capacity from these fossil assets. These contracts were transferred to us. In addition, we have entered into long-term power purchase agreements with independent power producers.

Dispatch and Fuel Types. Power generation facilities can generally be categorized into three classes based on the amount of time that the facilities are operating and their variable costs to produce electricity. A facility's variable cost to produce electricity, in turn, determines the order in which it is used to meet fluctuations in electricity demand. Base-load facilities are those that typically have low variable costs and provide power at all times when available. Base-load facilities are used to satisfy the base level of demand for power, or "load," that is not dependent upon time of day or weather. Peaking facilities have the highest variable cost to generate electricity and typically are used only during periods of highest demand for power. Intermediate facilities have cost and usage characteristics in between those of base-load and peaking facilities.

The following charts provide a breakdown of our generation assets and investments by dispatch and fuel type, as of December 31, 2001:

Power Team, our wholesale marketing division, markets power nationally 24 hours a day, 7 days a week. Power Team schedules power for customers and dispatches our owned and operated generation facilities, including the AmerGen facilities, but excluding the Sithe facilities. Power Team has experience and resources capable of meeting the energy needs of customers throughout the country.

We have entered into bilateral long-term contracts for sales of energy to load-serving entities, including electric utilities, municipalities, electric cooperatives, and retail load aggregators. We have also entered into agreements to deliver energy to wholesale market participants, whose primary focus is the resale of energy products for delivery. We deliver our energy to these customers through access to transmission assets or rights for transmission service.

We compete nationally in the wholesale electric generation markets on the basis of service offerings and price, using our generation assets to assure customers of energy delivery. To the extent that our resources exceed our contractual commitments, we market those resources on a short-term basis.

The following table sets forth at December 31, 2001 the net generation capacity of, and other information about, the stations that we own directly:

We operate all of the facilities except for Salem, which is operated by PSEG Nuclear LLC, Keystone and Conemaugh, which are operated by Reliant Energy, and LaPorte, which is operated by Air Products.

Nuclear facilities represent 73% of our directly owned generation capacity. Nuclear facilities are base-load plants. In 2001, approximately 54% of our electric supply was generated from the nuclear facilities.

The following table sets forth the capacity factors for our nuclear facilities for the last five years.

		Year Ended December 31,
Capacity Factors of Our Nuclear Facilities
	1997		1998		1999		2000		2001
Nuclear facilities previously owned by PECO		90	%	86	%	93	%	92	%	93	%
Nuclear facilities previously owned by ComEd(1)		49		65		89		93		95

Nuclear facilities are subject to comprehensive regulation by the NRC under the Atomic Energy Act of 1954. See "Regulation." Nuclear units are operated under licenses granted by the NRC, which specify permitted operations of the unit and which must be amended to reflect certain changes in operation and plant modifications.

Licenses. We have 40-year operating licenses for each of our nuclear units. We applied to the NRC in July 2001 for extension of the Peach Bottom 2 and 3 licenses and we expect to apply for the extension of the operating license for Dresden 2 and 3 and Quad Cities in 2003. AmerGen is reviewing the potential for license extensions for Oyster Creek and Three Mile Island. The operating license extension process takes approximately four to five years from the commencement of the project until completion of the NRC's review. The NRC review process takes approximately two years from the docketing of an application. Each requested license extension is expected to be for 20 years beyond the current license period. The following table summarizes operating license expiration dates for our nuclear facilities in service.

Station	Unit	In-Service Date	Current License Expiration
Braidwood	1	1988	2026
	2	1988	2027
Byron	1	1985	2024
	2	1987	2026
Dresden	2	1970	2009
	3	1971	2011
LaSalle	1	1984	2022
	2	1984	2023
Quad Cities	1	1973	2012
	2	1973	2012
Limerick	1	1986	2024
	2	1990	2029
Peach Bottom	2	1974	2013
	3	1974	2014
Salem	1	1977	2016
	2	1981	2020

Fuel. The fuel costs for nuclear generation are substantially less than those of fossil-fuel generation. Consequently, nuclear generation is the most cost-effective way for us to meet our commitment to supply the requirements of ComEd and PECO and for sales to others.

The cycle of production of nuclear fuel includes the mining and milling of uranium ore into uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, the enrichment of the uranium hexafluoride, and the fabrication of fuel assemblies.

We have uranium concentrate inventory and supply contracts sufficient to meet all of our uranium concentrate requirements through 2003. Our contracted conversion services are sufficient to meet all of our uranium conversion requirements through 2004. All of our enrichment requirements have been contracted through 2004. Contracts for fuel fabrication have been obtained through 2005. We do not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment or fabrication services for our nuclear units.

We obtain approximately 25% of our uranium enrichment services from European suppliers. There is an ongoing trade action by USEC, Inc. alleging dumping in the United States against European enrichment services suppliers. In January 2002, the U.S. International Trade Commission determined that USEC was "materially injured or threatened with material injury" by low-enriched uranium exported by European suppliers. The U.S. Department of Commerce has assessed countervailing and anti-dumping duties against the European suppliers. Both USEC and the European suppliers have appealed these decisions. We are uncertain at this time as to the outcome of the pending appeals; however, as a result of these actions we may incur higher costs for uranium enrichment services necessary for the production of nuclear fuel.

The capacity factor of a nuclear unit depends in part on the duration of the unit's refueling outage. Each of our nuclear units has a scheduled refueling outage every two years. We have become an industry leader in reducing the duration of our refueling outages.

We operate all of our fossil and hydroelectric facilities other than La Porte, Keystone and Conemaugh. In 2001, approximately 3% of our electric output was generated from our owned fossil and hydroelectric generation facilities. The majority of this output was dispatched by the Power Team to support our power marketing activities.

We are in the process of extensively renovating the Conowingo and Muddy Run control systems to improve plant efficiency. We are planning to overhaul four units at Conowingo, which is expected to increase capacity by 10 MW per unit.

The controls at all our combustion turbine facilities have been re-configured to provide remote start capability for all units, enabling immediate response time to capture fluctuations in electric market prices.

Fuel Management. Coal is obtained for our coal-fired plants primarily through annual contracts with the remainder supplied through either short-term contracts or spot-market purchases.

Some of our fossil generation stations can use either oil or gas as fuel. Natural gas is procured through annual, monthly and spot-market purchases. Fuel oil inventories are managed such that in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months inventory levels are managed to take advantage of favorable market pricing. In 2001, Power Team started to use financial instruments to mitigate price risk associated with multi-commodity price exposures. We also hedge forward price risk with both over-the-counter and exchange-traded instruments.

Licenses. Fossil generation plants are generally not licensed and, therefore, the decision on when to retire plants is fundamentally an economic one. Hydroelectric plants are licensed by FERC. The Muddy Run and Conowingo facilities have licenses that expire in September 2014. We are considering applying to FERC for license extensions of 40 years for both plants, but the duration of any license extension will depend on then-current policies at FERC. The process of applying for an extension to an existing hydroelectric license generally takes at least eight years.

In addition to our owned generation assets, we sell electricity that we purchase under the long-term contracts described below:

We are a party to contracts with Midwest Generation, LLC, a subsidiary of Edison Mission Energy. Under the contracts, we initially had the right to purchase through 2004 the capacity and energy associated with approximately 9,460 MW of fossil-fired generation stations located in Northern Illinois, formerly owned by ComEd. The generation units include base-load, intermediate and peaking units. Under the contracts, we pay a fixed capacity charge that varies by season and a fixed energy charge. The capacity charge is reduced to the extent the plants are unable to generate and deliver energy when requested. Under the contracts, we have annual rights to reduce the capacity and related energy that we are obligated to purchase, and we recently exercised some of these rights. Effective January 1, 2002, we have released all of the 355 MW of oil-fired peaking capacity that is covered by the contracts. We will decide whether to exercise yearly options in 2003 and 2004 depending on our projected need for capacity and energy to fulfill our obligations under our agreement with ComEd or otherwise, taking into account forward market conditions and other alternatives. We are also in arbitration with Midwest Generation under the contract relating to the unavailability of certain units in January 2001.

We own 49.9% of Sithe Energies, Inc. Another subsidiary of Exelon acquired the Sithe interest on December 18, 2000 for $696 million and $8 million of acquisition costs, and transferred it to us in January 2001 in connection with Exelon's corporate restructuring. Sithe, headquartered in New York, is a leading independent power producer, with ownership interests in 27 facilities in North America. Sithe has net generation capacity of 3,371 MW, primarily in New York and Massachusetts, 2,651 MW under construction and 2,400 MW in advanced development.

For the year ended December 31, 2001, Sithe had annual revenues (excluding revenues from operations disposed of during 2001) of approximately $1 billion. On December 31, 2001, Sithe had long-term debt of approximately $2.3 billion, including $2.1 billion of non-recourse project debt and excluding $107 million of non-recourse project debt associated with Sithe's equity investments. In December 2001, Sithe entered into a new 18-month corporate credit facility for $500 million expiring in June 2003. As of December 31, 2001, Sithe had drawn approximately $176 million under this facility and extended approximately $161 million in letters of credit. In connection with that credit facility, Exelon agreed to provide the lenders with a support letter confirming its investment in Sithe and Exelon's agreement to maintain a positive net worth of Sithe. Through internally generated cashflows and the corporate credit facility, Sithe has sufficient liquidity to cover all 2002 operating and capital commitments.

Sithe also holds other international assets, which are accounted for by Sithe as "held for sale" consistent with Sithe's strategy to exit the international power-development business and are not shown on the table. Proceeds from their sale, to the extent the proceeds are greater or less than the assets' net book value, will be solely for the account of the holders of the remaining 50.1% interest in Sithe. Proceeds from their sale equal to the assets' net book value will be solely for our account.

A majority of Sithe's merchant capacity is located in the Boston area. These facilities were purchased from Boston Edison Company in 1997. Prior to the purchase of these facilities, Sithe received authority from FERC to sell energy and capacity and ancillary services at market-based rates.

Purchase Option. Beginning December 18, 2002, we will have the right to purchase all (but not less than all) of the remaining outstanding shares of the Sithe common stock. The option expires on December 18, 2005. In addition, each of Sithe's other stockholder groups will have the right to require us to purchase all (but not less than all) of its shares during the same period in which we can exercise our option. At the end of that period, if we have not exercised our purchase option and the other Sithe stockholders have not exercised their put rights, we will have a one-time option to purchase shares

from the other stockholders to bring our holdings to 50.1% of the total outstanding shares. If we exercise our option or if all the stockholder groups exercise their put rights, the purchase price for 70% of the remaining 50.1% of the Sithe stock will be set at a fair market value plus a 10% premium in the case of a call or 10% discount in the case of a put, subject to a floor of $430 million and a ceiling of $650 million, and the remaining portion will be valued at fair market value, subject to a floor price of $141 million and a ceiling price of $330 million, plus, in each case, interest accrued from the beginning of the exercise period.

Under the terms of a stockholders' agreement, Sithe's board of directors consists of six directors, of which we have the right to nominate three. The approval of the majority of the entire board is required for certain actions, including approval of any agreement to purchase or sell electricity that will not be fully performed, or that is not terminable without penalty, before December 18, 2003. The approval of two-thirds of the stockholders is required to take certain actions, including incurring recourse debt in excess of $25 million.

Sithe's qualifying facilities (each a "QF") generally have been financed with non-recourse project finance debt and have entered into long-term, fixed rate contracts with various utilities. The debt and the contracts with the utilities are secured by the QF assets.

We are restricted under PUHCA from owning more than 50% of any QF. Accordingly, Sithe has agreed to use commercially reasonable efforts to sell or otherwise restructure each QF so as not to prohibit the purchase from occurring. In the event that the QFs are not sold or restructured at the time of the purchase of the remaining interest in Sithe, we may need alternative holding structures so as not to prohibit the purchase. Sithe is undertaking a comprehensive review of each QF.

Construction. Sithe's most significant construction projects are the Mystic 8 and 9 and ForeRiver plants, located in the Boston area. Both projects are intended to be merchant facilities and have been financed on a project finance basis, with recourse for repayment of the debt limited to the assets the Sithe project entity.

Washington Group International ("WGI"), as a result of its purchase of Raytheon Engineers & Constructors, Inc., served as the engineering, procurement, and construction ("EPC") contractor for the Mystic 8 & 9 and Fore River projects. In March 2001, WGI abandoned the projects and was terminated by Sithe as EPC contractor. Shortly thereafter, Raytheon, as guarantor of the EPC contractor's obligations under the applicable EPC agreements, stepped in to recommence construction activities at the project sites. WGI, recently reorganized under the federal bankruptcy laws, has been engaged by Raytheon to assist in completing the projects.

Originally, the commercial operation date for Mystic 8 & 9 under the EPC contract was April 19, 2002 and for Fore River was May 31, 2002. Because of delays in construction, Raytheon's project schedules for Mystic 8 & 9 and Fore River call for these projects to be available for operation on July 10, 2002, October 19, 2002 and September 2, 2002, respectively, but it is not certain that such objectives will be met. The EPC agreements call for liquidated damages to be paid to Sithe in the event of unexcused delays in the commercial operation date. Also, as a result of these delays, Sithe is liable for damages to its fuel supplier for its inability to accept a minimum amount of gas as originally scheduled.

Other Matters. On May 14, 2001, NSTAR Electric & Gas Corporation, the successor entity to Boston Edison, filed a complaint with FERC pursuant to section 206 of the Federal Power Act against four of Sithe's New England subsidiaries and PG&E Energy Trading. In the complaint, NSTAR accuses the four Sithe subsidiaries and PG&E of holding market power in generation in and around Boston and of engaging in bidding practices that capitalize on transmission constraints in the Boston area to drive up electricity prices. Sithe's response to the complaint was filed on June 4, 2001. In its filing, Sithe asserted that NSTAR's complaint is without merit and that the governing precedents support

continuance of Sithe's market-based rate authority and preclude the grant of the refunds sought by NSTAR. Since June 4, 2001, NSTAR and Sithe have each filed several pleadings further detailing their positions. In addition, ISO-New England filed an answer to NSTAR's complaint in support of Sithe. Sithe also responded to NSTAR's protest of the three-year market update filing of Sithe's FERC jurisdictional affiliates. FERC has not yet taken any action in these matters.

The Independence power station is a gas-fired power plant located in Scriba, New York directly owned by Sithe Independence Power Partners ("SIPP"). On June 29, 2001, Sithe restructured the Independence project. As part of this restructuring, SIPP amended its long-term gas supply agreement with Enron North America Corp. ("ENA") and Sithe sold an indirect 40% limited partnership interest in SIPP to an Enron Corp subsidiary for $186 million. As a result of restructuring, SIPP entered into a $419.3 million secured subordinated loan. The loan bears interest at an annual rate of 7%, which is payable semi-annually beginning on December 1, 2001. The principal amount of the loan will be repaid in 40 semi-annual installments commencing June 1, 2015. In connection with the restructuring, SIPP also entered into tolling arrangements for the Independence Project with Dynegy Power Marketing, Inc. that commenced on July 1, 2001 and run through 2014.

AmerGen Energy Company, LLC was formed in 1997 by PECO and British Energy plc, a Scottish corporation, to acquire and operate nuclear generation facilities in North America. Currently, AmerGen owns three single-unit nuclear generation facilities which are described in the table below. AmerGen operates these nuclear facilities; however, we provide AmerGen with many services, including management services, in connection with the operation and support of these facilities under a Services Agreement dated March 1, 1999. In addition, our chief nuclear officer holds the same position at AmerGen. See "Certain Transactions—AmerGen Services Agreement." As part of the restructuring, PECO transferred its 50% interest in AmerGen to us in January 2001.

The capacity factors for the AmerGen plants for 1999, 2000 and 2001 were 57%, 87% and 88.5%, respectively. The 1999 capacity factor reflects the shutdown of Clinton for the portion of 1999 prior to our acquisition.

As part of each acquisition of its nuclear facilities, AmerGen entered into a power sales agreement with the seller. The agreement with Illinois Power Company for Clinton is for 75% of the output for a term expiring at the end of 2004. Under a 1999 power purchase agreement, we purchase from AmerGen all of the residual energy for Clinton through December 31, 2002. The agreement with GPU, Inc. for Oyster Creek is for all of the output and expires on March 31, 2004. We buy the output of TMI pursuant to an agreement with AmerGen that expires on December 31, 2014.

AmerGen maintains a decommissioning trust fund for each of its plants in accordance with NRC regulations and believes that amounts in these trust funds, together with investment earnings thereon

and additional contributions for Clinton from Illinois Power, will be sufficient to meet its decommissioning obligations.

Under its LLC Agreement, AmerGen is managed by or at the direction of a management committee, which consists of six voting representatives, three of whom are appointed by British Energy and three by us. In addition, we appoint the chairman of the management committee. Action by the management committee generally requires the affirmative vote of a majority of members.

We may transfer our interest in AmerGen, as may British Energy, subject to a right of first refusal of the other party and to the right of the other party to require a third party buying the interest to also purchase the other party's interest.

In February 2002, Generation entered into an agreement to loan AmerGen up to $75 million at an interest rate of 1-month London Interbank Offering Rate plus 2.25%. As of March 31, 2002, $46 million has been loaned to AmerGen. The loan is due November 1, 2002.

Exelon has committed to provide AmerGen with capital contributions equivalent to 50% of the purchase price of any acquisitions AmerGen makes in 2002.

We are growing our portfolio by investing in plant modifications through investments and acquisitions, among them our investments in Sithe and AmerGen. In addition, in July 2001 we applied to the NRC for extension of the Peach Bottom 2 and 3 licenses and we expect to apply for extensions of operating licenses for Dresden 2 and 3 and Quad Cities in 2003. AmerGen is reviewing the potential for license extensions for Oyster Creek and TMI.

In December 2001, we agreed to purchase two generation plants located in the Dallas-Fort Worth metropolitan area from TXU Corp. to expand its presence in the Texas region. The $443 million purchase of the two natural-gas and oil-fired plants, to be financed through available cash and borrowings from Exelon, will add approximately 2,334 MW capacity. The transaction includes a power purchase agreement and tolling agreement for TXU to purchase power during the months of May through September from 2002 through 2006. During the periods covered by the power purchase agreement, TXU will make fixed capacity payments and will provide us fuel in return for exclusive rights to the energy and capacity of the generation plants. The closing of the acquisition is contingent upon receipt of the necessary regulatory approvals and is anticipated to occur in the second quarter of 2002.

We are in the process of increasing the capacity and output of our nuclear fleet through power uprates, plant modifications and refinements. These projects, which have the potential of adding up to 885 MW of capacity by the end of 2003, require NRC approval. For example, in December 2001, the NRC approved power uprates for Dresden Units 2 and 3 (allowing an increase of approximately 17% above the current rated thermal power) and Quad Cities Units 1 and 2 (allowing an increase of approximately 17.8% above the current rated thermal power). We constantly seek opportunities to improve the power output of each station by applying new technology, engineering upgrades and design improvements.

We are in the process of constructing a 350 MW gas-fired peaking facility in Chicago together with Peoples Energy Resources Corp. We expect the facility to begin operations in the summer of 2002.

In 2001, we completed the purchase of an additional 3.755% interest in the Peach Bottom Station from Atlantic City Electric Company. Total cash paid for the additional interest, including nuclear fuel, was $7 million. As part of this purchase, nuclear decommissioning funds of $29 million were also transferred to us. We are now a 50% owner of Peach Bottom.

Pebble Bed Modular Reactor. We are a 12.5% stakeholder in Pebble Bed Modular Reactor (Pty) Ltd., which is a consortium of investors (including British Nuclear Fuels, ESKOM Enterprises and the Industrial Developmental Corporation of South Africa) which is studying the feasibility of building a demonstration reactor in South Africa and commercializing the Pebble Bed design. There are a number of potential safety and economic advantages that have drawn favorable interest in the PBMR technology: the reactor modulars are small; they require less construction time; they are refueled without requiring a shut down; they do not require large external cooling water sources; and they are inherently safer than light water reactors. As a new technology, PBMR must address many first-of-a-kind issues. In addition, the cost of the final product to the end user must be competitive with alternative energy sources. The decision by the members of the consortium to move ahead with finalizing the design and construction of a demonstration plant in South Africa was due to be made in November 2001, but was delayed for up to a year to resolve a number of technical issues. We believe that the PBMR technology is feasible; however, significant work remains to determine the commercial viability of the technology for use as an alternative electric energy generation source.

Development of New Uranium Centrifuge Plant. In December 2001, we signed an agreement to purchase general and limited partnership interests in Louisiana Energy Services, L.P. ("LES") totaling 6.75% from Graystone Corporation and Le Paz Incorporated, respectively. We expect to close on the acquisition of these interests in April 2002. LES was formed in the early 1990s by a consortium of companies to design, build and operate a private uranium enrichment facility. LES was officially abandoned in 1998 because, among other reasons, there was a perceived weakness in demand for uranium enrichment services due to uncertainly about the outlook for nuclear power in the U.S. In the last several years, the regulatory climate and market conditions have turned more favorable. For example, since the NRC has successfully processed license extension applications and power uprates, the long-term outlook for the uranium enrichment market may be stronger than previously believed, although future demand for uranium enrichment cannot be predicted with certainty. However, Exelon's need for a reliable competitively priced supply of enriched uranium is clear.

LES, through its principal partner Urenco, has notified the NRC of its plans for submitting an application to license a new centrifuge uranium enrichment plant in the U.S. We and Urenco are part of what is expected to be a realigned LES consortium, which would also include Duke Energy and Entergy. LES has requested an opportunity to begin a pre-application review process with the NRC, with a view towards submitting an application to the NRC in the fourth quarter of 2002. The LES consortium is currently working to site the new facility. We do not expect these costs to be material to us.

Several additional factors may affect the companies' plans. One factor relates to the potential for significantly enhanced security requirements in light of the events of September 11, 2001, which in turn would add cost. Another situation involves USEC Inc.'s recent statements about the possible expansion of its uranium enrichment capacity by constructing new gas centrifuge machines. These apparent plans are related to the continuing negotiations between USEC Inc. and Russia's Techsnabexport to finalize a new 12-year agreement on the sale of uranium to the U.S. from Russian high-enriched uranium. A final factor is the continuation of an agreement that severely restricts the amount of enriched uranium that can be imported into the United States from Russia. The Russian Federation has petitioned for a review of this agreement to have the restriction removed in 2004.

Power Team manages our supply obligations to ComEd, PECO and other wholesale customers by:

Power Team competes nationally in wholesale power marketing on the basis of price and service offerings, using our generation assets, transmission access, reservations and its knowledge of the interconnected bulk power systems and developing markets to assure customers of energy delivery. Through Power Team, we enter into bilateral arrangements for the purchase, sale and delivery of capacity, energy and ancillary services. Sales agreements are with load-serving entities, including electric utilities, municipalities, electric cooperatives, retail load aggregators and other wholesale market participants. Through Power Team, we also compete in the wholesale spot markets for electricity.

We have agreements with ComEd and PECO to supply their respective load requirements for customers through 2006 and 2010, respectively. Under the agreements with ComEd and PECO, we will supply all of ComEd and PECO's needs to supply customers who do not select an alternative electric generation supplier through the end of the respective transition periods. Therefore, the supply requirements under the agreements will vary depending on how much of the load has selected an alternative supplier.

Power Team also manages the price and supply risks for energy and fuel associated with our generation assets and the risks of our power marketing activities. Through Power Team, we began to use financial and commodity contracts for trading purposes in the second quarter of 2001. The trading activities represent a very limited portion of our overall power marketing activities. For example, the limit on new purchases of electricity for any forward month represents less than 5% of our owned and contracted supply of electricity. The trading portfolio is planned to grow modestly in 2002, subject to stringent risk management limits and policies including volume, stop-loss and value-at-risk limits to manage exposure to market risk. Additionally, we have a financial risk management policy and a corporate risk group to monitor the financial risks of our power marketing activities.

At December 31, 2001, we had long-term commitments, relating to the purchase and sale of energy, capacity and transmission rights from unaffiliated utilities and others, including the Midwest Generation and AmerGen contracts, as expressed in the following table:

In addition, in connection with the acquisition of the TXU generating stations, expected to close in the second quarter of 2002, we have agreed to supply TXU with 100% of the station output during the months of May through September from 2002 through 2006. During the periods covered by the power purchase agreement, TXU will make fixed capacity payments and will provide fuel to us in return for exclusive rights to the energy and capacity of the generation plants.

In the United States, there are four established, real-time power markets, which are administered by independent system operators: Pennsylvania, New Jersey, Maryland, LLC ("PJM"), which is in the Mid-Atlantic Area Council ("MAAC") region; New England and New York, which are both in the Northeast Power Coordinating Council ("NPCC") region, and California, which is in the Western Systems Coordinating Council ("WSCC") region. In each of these areas, power is traded through bilateral agreements between buyers and sellers and on the spot markets operated by independent system operators. In areas where there is no spot-market, electricity is purchased and sold solely through bilateral agreements. The facilities that were transferred to us by PECO, as well as two of AmerGen's facilities, are located in the PJM market. To the extent that these facilities have capacity available after our obligations to customers, including PECO and ComEd, have been met, Power Team sells into the PJM market, as well as under bilateral agreements inside and outside of the market. The facilities that were transferred to us by ComEd, the facilities that supply electricity to us under our agreements with Midwest Generation and AmerGen's Clinton facility are located in the Mid-America Interconnected Network region ("MAIN"), where there is no independently operated regional spot market. To the extent that these facilities have capacity available after our obligations to our customers, including ComEd, have been met, Power Team sells electricity in the wholesale markets. Sithe sells into the New England Power Pool ("NEPOOL") and, to a lesser degree, the New York market.

In addition to selling energy in PJM, New England and New York markets, generators can sell other energy-related products. These products differ from market to market and include, among others, regulation (and/or automatic generation control), unbundled capacity, and operating reserves.

PJM. The PJM market covers all or part of the states of Pennsylvania, New Jersey, Maryland, Delaware, Virginia, and the District of Columbia. PJM, one of the largest centrally dispatched power pools in the world, handles about 8% of United States electricity. The PJM market is expected to grow at an annual rate of 1.4% through 2020. PJM requires load-serving entities, such as PECO, to own or contract for capacity to cover their peak demand and reserve margins required by PJM, currently, 18%.

MAIN. The Mid-American Interconnected Network region includes Illinois and parts of Missouri, Wisconsin and Michigan. MAIN has a policy, but not a requirement, that companies maintain a reserve of at least 17% to 20% of their capacity for long-term planning. MAIN currently has a wholesale market consisting largely of informal arrangements, with most electricity sold through bilateral agreements, not a power exchange, but is rapidly progressing toward the formation of an independent system operator that will manage regional transmission assets and establish spot-market trading centers.

NEW ENGLAND. The New England market is one of the two established markets in the Northeast Power Coordinating Council and covers the six New England states. Peak demand in the New England market is forecasted to grow at an annual rate of 1.47% through 2020. The New England market structure includes markets for energy, automatic generation control, ten-minute spinning reserve, ten-minute non-spinning reserve and thirty-minute operating reserve.

NEW YORK. The New York market, also located in the NPCC region, covers the State of New York. Peak demand in the New York market is forecasted to grow at an annual rate of 0.8% through 2020. The New York market structure includes markets for installed capacity, day-ahead and real-time energy, day-ahead and real-time ancillary services, including reserves and regulation and installed capacity.

OTHER REGIONS. We also have long-term contracts for the purchase of energy in the Electric Reliability Council of Texas region (1,060 MW); the Southeastern Electric Reliability Council region (1,000 MW) and the Southwest Power Pool region (800 MW). None of these regions has an established spot market, although Texas has a balancing market.

We are subject to the jurisdiction of the NRC with respect to our nuclear generation stations. The Atomic Energy Act empowers the NRC to issue, modify, suspend and revoke licenses for the construction and operation of nuclear generation stations and impose civil penalties for failure to comply with the Act, the regulations under it or the terms of those licenses. The NRC subjects nuclear generation stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security, environmental and radiological aspects of those stations. The NRC also adopts regulations regarding decommissioning of nuclear facilities and insurance requirements for nuclear accidents, including a regulation requiring that, within 30 days of stabilizing a reactor, a licensee must submit a report to the NRC that provides a clean-up plan, identifying all clean-up operations necessary to decontaminate the reactor, to permit either the resumption of operation or decommissioning of the facility.

The NRC has revamped its inspection, assessment and enforcement programs for commercial nuclear power plants. The new oversight process uses more objective, timely and safety-significant criteria in assessing performance, while seeking to more effectively and efficiently regulate the industry. It also takes into account improvements in the performance of the nuclear industry over the past

twenty years. Nuclear plant performance is measured by a combination of objective performance indicators and by the NRC inspection program. These are closely focused on those plant activities having the greatest impact on safety and overall risk. In addition, the NRC conducts periodic reviews of the effectiveness of each operator's programs to identify and correct problems. The inspection program is designed to verify the accuracy of performance indicator information and to assess performance based on safety cornerstones that include:

The NRC evaluates licensee performance by analyzing two distinct inputs: inspection findings resulting from the NRC inspection program and performance indicators reported by the licensees on a quarterly basis. These inputs are typically color-coded. A "green" coding indicates performance within an expected performance level in which the related safety cornerstone objectives are met. A "white" coding indicates performance outside an expected range of nominal utility performance but related cornerstone objectives are still being met. A "yellow" coding indicates related cornerstone objectives are being met, but with a minimal reduction in safety margin. A "red" coding indicates a significant reduction in safety margin in the area measured by the performance indicator. The overall plant assessment by the NRC is based on a combination of the performance indicators and the NRC's inspection findings. Where all inputs are "green," the plant typically requires only routine oversight by the NRC. Where no more than two "white" findings are found in different cornerstones and cornerstone objectives are fully met, the NRC generally permits licensees to implement corrective actions to remedy the findings. Plants that do not meet the "safety cornerstone" objectives, measured by performance indicator and inspection findings, may receive increased inspection, focusing on areas of declining performance. There are also inspections beyond the baseline program, even at plants performing well, if there are operational problems or events the NRC believes require greater scrutiny. Generic problems, affecting some or all plants, may also require additional inspections.

NRC reactor oversight process results for the fourth quarter of 2001 for us and AmerGen indicate predominantly "green" inspection findings associated with the seven safety cornerstones as well as performance indicators. There were no "red" or "yellow" inspection findings or performance indicators at any of our plants. Eight units (Braidwood Unit 2, Byron Units 1 & 2, LaSalle Unit 1, Quad Cities Units 1 and 2, as well as Salem Units 1 and 2) all had "green" inputs (both performance indicators and inspection findings).

Of the remaining plants, six units (Clinton, Limerick Unit 1, Oyster Creek, Peach Bottom Units 2 and 3, and Three Mile Island) had one "white" finding each, while Limerick Unit 2 had two "white" findings in different cornerstones. Two units (Braidwood Unit 1 and LaSalle Unit 2) each had one "white" performance indicator.

Accordingly, all of our plants performed at levels satisfactory enough to receive routine NRC oversight with the opportunity to implement corrective actions to address any "white" findings.

With respect to nuclear power plant security issues, in response to the events of September 11, 2001, the NRC issued Safeguards and Threat Advisories to all nuclear power plant licensees, including us, requesting that they place their facilities on highest alert security status. In response to the NRC

Advisories and on our own initiative, we also implemented enhanced security measures, such as increased guard forces, the erection of additional physical barriers, and heightened communication with authorities at all levels of government. In addition to the Advisories, the NRC began an initiative to perform a "top to bottom" review of our safeguards and security programs and requirements in light of the events of September 11.

On February 25, 2002, the NRC issued immediately effective orders modifying the operating licenses for all nuclear power plants to require all licensees, including us, to implement certain interim security enhancements. In issuing the orders, the NRC found that these compensatory measures should be implemented "as prudent, interim measures, to address the generalized high-level threat environment.…" The orders direct all licensees to provide the NRC a schedule for achieving compliance with the requirements of the orders or explain site-specific circumstances to justify relief or variation from those requirements. In addition, if implementation of any requirement would adversely affect safe operation of a facility, a licensee may either propose an alternate plan for achieving the objectives of the order or provide the NRC a schedule for modifying the facility to address the adverse safety condition(s). All enhancements required by the orders are to be implemented by August 31, 2002. The orders are to remain in effect pending an NRC decision that changes in the threat environment justify a relaxation of the requirements or until the NRC determines that other changes are necessary following a re-evaluation of current security programs. The security requirements imposed by the NRC's orders issued to us will involve increased capital expenditures, at each of our nuclear stations, for such things as enhanced vehicle barriers, modifications to plant facilities and increased size of guard forces. We currently estimate the increased costs to be approximately $1 million per station.

There are no facilities for the reprocessing or permanent disposal of spent nuclear fuel ("SNF") currently in operation in the United States, nor has the NRC licensed any such facilities. We currently store all SNF generated by our nuclear generation facilities in on-site storage pools and, in the case of Peach Bottom and Dresden, some SNF has been placed in dry cask storage facilities. Our SNF storage pools do not have sufficient storage capacity for the life of the plant and we are developing dry cask storage facilities, as necessary, to support operations.

As of December 31, 2001, we had 37,300 SNF assemblies (9,200 tons) stored on site in SNF pools and dry cask storage. On site dry cask storage in concert with existing spent fuel storage is capable of

meeting all spent fuel storage requirements at our sites. The following table describes the current status of our SNF storage facilities:

Site		Date for Loss of Full Core Discharge
Dresden		Dry cask storage in operation
Quad Cities		2006
Byron		2011
LaSalle		2012
Braidwood		2013
Clinton		2006 (Plans to re-rack to increase SNF pool capacity)
Peach Bottom		Dry cask storage in operation
Limerick		2009
Oyster Creek		2000 (Dry cask storage project underway)(1)
TMI		Life of plant storage capable in SNF pool
Salem		2011

Under the Nuclear Waste Policy Act of 1982 (the "NWPA"), the United States Department of Energy (the "DOE") is responsible for the disposal of SNF and other high-level radioactive waste. ComEd and PECO each signed contracts with the DOE (each, a "Standard Contract") to provide for disposal of SNF from their respective nuclear generation stations. We assumed ComEd and PECO Standard Contracts as part of the restructuring, covering Byron, Braidwood, LaSalle, Quad Cities, Zion, Dresden, Limerick and Peach Bottom; AmerGen assumed the standard contracts for Clinton, Oyster Creek and TMI-1. In accordance with the NWPA and the Standard Contract, we pay the DOE one mill ($.001) per kilowatt-hour of net nuclear generation, net of station use, for the cost of nuclear fuel long-term storage and disposal. This fee may be adjusted in order to ensure full cost recovery by the DOE.

The Standard Contract required ComEd and PECO to pay the DOE a one-time fee applicable to nuclear generation through April 6, 1983. PECO has paid this fee while ComEd exercised its option to pay the one-time fee of $277 million, with interest, just prior to the first delivery of SNF to the DOE. As of December 31, 2001, the unfunded liability for the one-time fee with interest was $843 million. We assumed this obligation in the restructuring.

The NWPA and the Standard Contract required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 1998. The DOE, however, failed to meet that deadline and its performance is expected to be delayed significantly. The DOE's current estimate for opening an SNF permanent disposal facility is 2010. This extended delay in SNF acceptance by the DOE has led to the use of dry storage at the Dresden and Peach Bottom Units and consideration of dry storage at other units.

In July 1998, ComEd filed a complaint against the DOE in the U.S. Court of Federal Claims seeking to recover damages caused by the DOE's failure to honor its contractual obligation to begin disposing of SNF in January 1998. ComEd subsequently moved for partial summary judgment on liability for breach of contract claim. In August 2001, the Court granted ComEd's motion for partial

summary judgment for liability on ComEd's breach of contract claim. In November 2001, the DOE filed two partial summary judgment motions relating to certain damage issues in the case, as well as two motions to dismiss claims other than ComEd's breach of contract claim. The Court has deferred briefing on those motions pending completion of discovery on certain damage issues. We assumed this litigation in the restructuring.

In July 2000, PECO entered into an agreement with the DOE relating to Peach Bottom to address the DOE's failure to begin removal of SNF in January 1998, as required by the Standard Contract. Under that agreement, the DOE agreed to provide PECO (now us) with credits against PECO's future contributions to the nuclear waste fund over the next ten years to compensate for SNF storage costs incurred as a result of the DOE's breach of the Standard Contract. The agreement also provides that, upon PECO's request, the DOE will take title to the SNF and the interim storage facility at Peach Bottom, provided certain conditions are met. We have assumed this contract.

In November 2000, eight utilities with nuclear power plants filed a Joint Petition for Review against the DOE with the U.S. Court of Appeals for the Eleventh Circuit seeking to invalidate the portion of the agreement providing for credits to PECO against nuclear waste fund payments on the ground that such provision is a violation of the NWPA. PECO intervened as a defendant in that case, which is ongoing. On December 5, 2001, the United States Court of Appeals for the Eleventh Circuit held oral argument on the utilities' Joint Petition for Review. In April, 2001, an individual filed suit against the DOE with the United States District Court for the Middle District of Pennsylvania seeking to invalidate the agreement on the grounds that the DOE has violated the National Environmental Policy Act and the Administrative Procedure Act. PECO intervened as a defendant and moved to dismiss the complaint. The Court has not yet ruled on the motion to dismiss.

As a by-product of their operations, nuclear generation units produce low-level radioactive waste ("LLRW"). LLRW is accumulated at each generation station and permanently disposed of at Federally licensed disposal facilities. The Federal Low-Level Radioactive Waste Policy Act of 1980 (the "Waste Policy Act") provides that states may enter into agreements to provide regional disposal facilities for LLRW and restrict use of those facilities to waste generated within the region. Illinois and Kentucky have entered into an agreement, although neither state currently has an operational site, and none is currently expected to be operational until after 2011. Pennsylvania, which had agreed to be the host site for LLRW disposal facilities for generators located in Pennsylvania, Delaware, Maryland and West Virginia, has suspended the search for a permanent disposal site.

We have temporary on-site storage capacity at our nuclear generation stations for limited amounts of LLRW and have been shipping such waste to LLRW disposal facilities in South Carolina and Utah. The number of LLRW disposal facilities is decreasing, and we anticipate the possibility of continuing difficulties in disposing of LLRW. We are also pursuing alternative disposal strategies for LLRW, including a LLRW reduction program to minimize cost impacts.

The Energy Policy Act of 1992 requires that the owners of nuclear reactors pay for the decommissioning and decontamination of the DOE uranium enrichment facilities. The total cost to all domestic utilities covered by this requirement is estimated to be $150 million per year through 2006, of which our share is approximately $22 million per year.

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. Based on estimates of decommissioning costs for each of the nuclear facilities in which we have an ownership interest, the ICC permits ComEd and the PUC permits PECO to collect from its customers and deposit in segregated accounts amounts which, together with earnings thereon, will be used to decommission such nuclear facilities. As of December 31, 2001, our estimate of

our nuclear facilities' decommissioning cost is $7.2 billion in current year dollars. These expenditures are expected to occur primarily after the plants are retired and are currently estimated to begin in 2029 for plants currently in operation. Decommissioning costs are recoverable by ComEd and PECO through regulated rates and are remitted to us for deposit in the decommissioning trust funds. In 2001, ComEd and PECO collected from customers and remitted to us approximately $102 million in decommissioning costs. At December 31, 2001, the decommissioning liability recorded in accumulated depreciation and deferred credits and other liabilities was $2.7 billion and $1.3 billion, respectively. We believe that the amounts being remitted to us by ComEd and PECO and the earnings on nuclear decommissioning trust funds will be sufficient to fully fund our decommissioning obligations.

In connection with the transfer of ComEd's nuclear generating stations to us, ComEd asked the ICC to approve the continued recovery of decommissioning costs after the transfer. On December 20, 2000, the ICC issued an order finding that the ICC has the legal authority to permit ComEd to continue to recover decommissioning costs from customers for the six-year term of the power purchase agreements between ComEd and us. Under the ICC order, ComEd is permitted to recover $73 million per year from customers for decommissioning for the years 2001 through 2004. In 2005 and 2006, ComEd can recover up to $73 million annually, depending upon the portion of the output of the former ComEd nuclear stations that ComEd purchases from us. Under the ICC order, subsequent to 2006, there will be no further recoveries of decommissioning costs from customers. The ICC order also provides that any surplus funds after the nuclear stations are decommissioned must be refunded to customers. The ICC order is currently pending on appeal in the Illinois Appellate Court.

Zion, a two-unit nuclear generation station, and Dresden Unit 1 formerly owned by ComEd, have permanently ceased power generation. ComEd transferred Zion and Dresden Unit 1 as well as their related decommissioning liabilities and trust funds to us as part of Exelon's corporate restructuring. Zion's and Dresden Unit 1's spent nuclear fuel is currently being stored in on-site storage pools until a permanent repository under the NWPA is completed. We have recorded a liability of $1.3 billion, which represents the estimated cost of decommissioning Zion and Dresden Unit 1 in current year dollars. Decommissioning expenditures are expected to occur primarily after 2013 and 2030 for Zion and Dresden Unit 1, respectively.

General. Specific operations of ours are subject to regulation regarding environmental matters by the United States and by various states and local jurisdictions where we operate our facilities. The Illinois Pollution Control Board ("IPCB") has jurisdiction over environmental control in the state of Illinois, together with the Illinois Environmental Protection Agency, which enforces regulations of the IPCB and issues permits in connection with environmental control. The Pennsylvania Department of Environmental Protection ("PDEP") has jurisdiction over environmental control in the Commonwealth of Pennsylvania. State regulation includes the authority to regulate air, water and noise emissions and solid waste disposals. The United States Environmental Protection Agency ("EPA") administers certain Federal statutes relating to such matters as do various interstate and local agencies.

When the generation assets of PECO and ComEd were transferred to us, we agreed to assume environmental liabilities arising out of any violation of environmental laws, environmental permits or environmental claims related to any real property or asset transferred to us and to indemnify PECO and ComEd, their permitted assigns and their respective officers, directors, stockholders and employees against all fines or penalties, liabilities, damages and losses related to environmental claims. PECO and ComEd transferred to us all indemnities, hold harmless agreements and funds, reserves, escrows and other repositories of funds related to environmental obligations associated with the units we acquired and kept all liabilities for all substantial transmission and distribution facilities.

Water. Under the Federal Clean Water Act, National Pollutant Discharge Elimination System ("NPDES") permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated. Those permits must be renewed periodically. We either have NPDES permits for all of our generation stations or have pending applications for such permits. We are also subject to the jurisdiction of certain other state agencies, including the Delaware River Basin Commission and the Susquehanna River Basin Commission.

Solid and Hazardous Waste. The Comprehensive Environmental Response; Compensation, and Liability Act of 1980, as amended ("CERCLA"), provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. Government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of waste at sites, most of which are listed by the EPA on the National Priorities List ("NPL"). These potentially responsible parties ("PRPs") can be ordered to perform a cleanup, can be sued for costs associated with an EPA-directed cleanup, may voluntarily settle with the U.S. Government concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation under state oversight prior to listing on the NPL. Various states, including Pennsylvania and Illinois, have enacted statutes that contain provisions substantially similar to CERCLA. In addition, the Resource Conservation and Recovery Act ("RCRA") governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted.

By notice issued in November 1986, the EPA notified over 800 entities, including PECO and ComEd, that they may be PRPs under CERCLA with respect to releases of radioactive and/or toxic substances from the Maxey Flats disposal site, a LLRW disposal site near Moorehead, Kentucky, where PECO and ComEd wastes were deposited. A settlement was reached among the Federal and private PRPs including ComEd and PECO, the Commonwealth of Kentucky and the EPA concerning their respective roles and responsibilities in conducting remedial activities at the site. Under the settlement, the private PRPs agreed to perform the initial remedial work at the site and the Commonwealth of Kentucky agreed to assume responsibility for long-range maintenance and final remediation of the site. On April 18, 1996, a consent decree, which included the terms of the settlement, was entered by the United States District Court for the Eastern District of Kentucky. The PRPs have entered into a contract for the design and implementation of the remedial plan and work has commenced. As a result of the restructuring of Exelon, we have agreed to assume ComEd's and PECO's liability and obligations arising from the Maxey Flats site. We estimate that our share of remediation costs will not be material.

Air. Air quality regulations promulgated by the EPA, the PDEP and the City of Philadelphia in accordance with the Federal Clean Air Act and the Clean Air Act Amendments of 1990 (the "Amendments") impose restrictions on emission of particulates, sulfur dioxide (SO₂), nitrogen oxides (NO_X) and other pollutants and require permits for operation of emission sources. We have obtained such permits and they must be renewed periodically.

The Amendments establish a comprehensive and complex national program to substantially reduce air pollution. The Amendments include a two-phase program to reduce acid rain effects by significantly reducing emissions of SO₂ and NO_X from electric power plants. Flue-gas desulfurization systems (scrubbers) have been installed at all of our coal-fired units other than the Keystone Station. Keystone is subject to, and in compliance with, the Phase II SO₂ and NO_X limits of the Amendments, which became effective January 1, 2000. We and the other Keystone co-owners are purchasing SO₂ emission allowances to comply with the Phase II limits.

We have completed implementation of measures, including the installation of NO_X emissions controls and the imposition of certain operational constraints, to comply with the Reasonably Available Control Technology Limitations of the Amendments. We expect that the cost of compliance with anticipated air-quality regulations may be substantial due to further limitations on permitted NO_X emissions:

The EPA has issued two regulations to limit NO_X emissions from power plants in the eastern United States to address the "ozone transport" issue. The first regulation was issued on September 24, 1998. The original NO_X regulation covered power plants in the 22 eastern states and had an effective date of May 1, 2003. As a result of litigation at the D.C. Circuit Court of Appeals, the original NO_X regulation was revised to cover 19 eastern states (rather than the original 22) and the effective date was delayed by approximately one year to May 31, 2004. In most other respects, the original NO_X regulation was substantively upheld by the Court. Both Pennsylvania and Illinois power plants are covered by the original NO_X regulation.

The second EPA regulation, referred to as the "Section 126 Petition Regulation" was issued on May 25, 1999. This regulation was issued by the EPA in response to downwind state (Connecticut, Maine, Massachusetts, New Hampshire, New York, Pennsylvania, Rhode Island, Vermont) complaints under Section 126 of the Clean Air Act that upwind state NO_X emissions were negatively impacting downwind states' ability to attain the Federal ozone standard. The Section 126 Petition Regulation requires substantively the same NO_X reduction requirement for the power generation sector as the original NO_X regulation. However, the Section 126 Petition Regulation covers fewer states (Delaware, Indiana, Kentucky, Maryland, Michigan, North Carolina, New Jersey, New York, Ohio, Virginia and West Virginia). It does not cover power plants in Illinois. The compliance date of the Section 126 Petition Regulation, originally set for May 1, 2003, was tolled by the D.C. Circuit Court of Appeals pending resolution of several issues. Despite this delay, the northeast states covered by the Section 126 Petition Regulation are still expected to comply with the original May 1, 2003 compliance date.

On September 23, 2000, Pennsylvania issued final state NO_X reduction regulations for power plants to satisfy both the original NO_X regulation and the Section 126 Petition Regulation. The Pennsylvania regulation is effective May 1, 2003. Exelon is currently evaluating options to comply with the new Pennsylvania regulations. These options include limiting the operation of our fossil-fired units, purchasing NO(x) emission allowances from the allowance market, installing additional control equipment or a combination of these alternatives. For Keystone, the co-owners have approved and started preliminary work for the installation of selective catalytic reduction units to comply with the new regulations.

Many other provisions of the Amendments affect our business activities. The Amendments establish stringent control measures for geographical regions which have been determined by the EPA to not meet National Ambient Air Quality Standards; establish limits on the purchase and operation of motor vehicles and require increased use of alternative fuels, establish stringent controls on emissions of toxic air pollutants and provide for possible future designation of some utility emissions as toxic; establish new permit and monitoring requirements for sources of air emissions, and provide for significantly increased enforcement power, and civil and criminal penalties.

The Federal Power Act gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to FERC's jurisdiction are required to file rate schedules with FERC with respect to wholesale sales or transmission of electricity. Tariffs established under FERC regulation give us access to transmission lines that enable us to participate in competitive wholesale markets.

Because we sell power in the wholesale markets, we are deemed to be a public utility for purposes of the Federal Power Act and are required to obtain FERC's acceptance of our rate schedules for wholesale sales of electricity. We have received authorization from FERC to sell energy at market-based rates. As is customary with market-based rate schedules, FERC reserved the right to suspend market-based rate authority on a retroactive basis if it is subsequently determined that we or any of our affiliates exercised or have the ability to exercise market power. FERC is also authorized to order refunds if it finds that market-based rates are unreasonable.

In April 1996, FERC issued Order 888. The intent of Order 888 was to open the transmission grid subject to FERC's jurisdiction to eligible customers, including sellers of power and retail customers, in states where retail access is approved. Order 888 requires that owners of transmission facilities provide access to their transmission facilities under filed tariffs at cost-based rates. In connection with Order 888, FERC issued Order 889. Under Order 889, PECO and ComEd were required to file Standards of Conduct, which governed the communication of non-public information between transmission personnel and employees of any affiliated wholesale merchant function. FERC recently issued a Notice of Proposed Rulemaking for the Standards of Conduct for Transmission Providers. Among other things, FERC is considering whether it would be appropriate for it to adopt measures that would limit the amount of capacity an affiliate can hold in a transmission provider and revising the policy of interruption of transportation. Our business would be impacted if any of these measures is instituted.

In December 1999, FERC issued Order 2000 which encourages the voluntary restructuring of transmission operations through the use of independent system operators ("ISOs") and regional transmission organizations ("RTOs"). The establishment of these entities is intended to eliminate or reduce transmission charges imposed by successive transmission systems when wholesale generators cross several transmission systems to deliver capacity. Under Order 2000, each transmission-owning public utility was required to file a plan to form an RTO, with December 2001 as the target date for operation. In July 2001, FERC conditionally granted RTO status to PJM and, in separate orders, directed that the various proposed RTOs combine into four regional RTOs. However, inconsistencies in the pace of RTO development and significant state public utility commission concerns caused FERC to indefinitely extend its operational target date of December 2001.

The latter half of 2001 and early 2002 have brought further change to the electric industry. In early November 2001, FERC announced its intent to complete RTO development using two parallel tracks: (1) address geographic scope and governance of RTOs; and (2) address transmission pricing and market design. Contemporaneously, FERC initiated several immediate steps to move the RTO development process forward. One of these actions was initiation of an effort to standardize generator interconnection (a related effort concerning cost allocation is to be addressed in 2002). Also, FERC issued a Notice of Proposed Ruling on Revised Public Utility Filing Requirements, pursuant to which it is considering mandatory electronic filing of transactional data and additional public filing requirements.

FERC announced in late November 2001 a new market power test, the Supply Margin Assessment (SMA) screen. Under the SMA, if within a particular geographic market an energy company's generation capacity exceeds the market's surplus capacity above peak demand then the test is failed. If this occurs, FERC will impose on the company and its affiliates a requirement to offer uncommitted capacity under a cost-based rate structure. The only exemption will be for companies operating under the authority of an ISO or RTO with a FERC-approved market monitoring and mitigation plan. Under this approach, it would be unlikely that a vertically integrated energy company serving franchised retail load would be able to pass the test and maintain market-based rates, unless and until the company was a member of an approved ISO or RTO.

FERC also continues to exhibit a commitment to increased market monitoring with an intent to ensure that significant price volatility, such as was seen in California, does not occur again. As part of

this commitment, FERC announced early in 2002 the formation of the Office of Market Oversight and Investigation which will report directly to the FERC Chairman. This new office will assess, among other things, market performance. It is unclear how our business may be affected by these initiatives.

In 2001, FERC approved the Midwest ISO (MISO) as an RTO, which principally resides within the MAPP reliability region, as an RTO. At the same time, FERC rejected the stand alone, for-profit RTO structure proposed by the Alliance Companies. FERC, however, indicated that a for-profit transmission company could be formed and successfully integrated into the MISO. Currently, approximately 25% of our generation is located within the proposed PJM RTO area, other significant generation is located in the MAIN reliability region, where an approved ISO or RTO does not exist. It is possible that under its evolving market power tests, FERC may determine that we have market power in this area. If FERC were to suspend our market-based rate authority, it would most likely be necessary to file to obtain FERC acceptance of cost-based rate schedules or schedules tied to a public index. In addition, the loss of market-based rate authority would subject us to the accounting, record-keeping and reporting requirements that are imposed on public utilities with cost-based rate schedules.

We are subject to regulation under the Public Utility Holding Company Act as a registered public utility holding company and as a wholly owned subsidiary of Exelon, which is also a registered public utility holding company. The restrictions under PUHCA generally involve financing, investments and affiliate transactions. Under PUHCA, we cannot issue debt or equity securities or guaranties without the approval of the SEC. Exelon and its subsidiaries currently have approval to issue up to an aggregate of $4 billion of common stock, preferred securities, long- and short-term debt, and to issue up to $4.5 billion of guarantees. Exelon also requested, and the SEC reserved jurisdiction over, an additional $4 billion in financing authorization. Under PUHCA, generally, we can invest only in traditional electric and gas utility businesses and related businesses. Our investments in exempt wholesale generators and foreign utility companies are limited to $4 billion in the aggregate. The acquisition of the voting stock of other gas or electric utilities is subject to prior SEC approval. In addition, PUHCA requires that all of a registered holding company's utility subsidiaries constitute a single system that can be operated in an efficient, coordinated manner. PUHCA also imposes restrictions on transactions among affiliates.

The Price-Anderson Act limits the liability of nuclear reactor owners to $9.5 billion for claims arising from a single incident. The current limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors. We carry the maximum available commercial insurance of $200 million and the remaining $9.3 billion is provided through mandatory participation in a financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed up to $89 million per reactor per incident, payable at a rate of no more than $10 million per reactor per incident per year. This assessment is subject to inflation and state premium taxes. In addition, the U.S. Congress could impose revenue raising measures on the nuclear industry to pay claims. The Price-Anderson Act is scheduled to expire in August 2002. Although replacement legislation has been proposed from time to time, we are unable to predict whether replacement legislation will be enacted. The Price-Anderson Act and the extensive regulation of nuclear plants by the NRC do not preclude claims under state law for personal, property or punitive damages related to radiation hazards.

Liability of owners of nuclear power plants currently licensed by the NRC to operate would continue to be limited by the Price-Anderson Act provisions regardless of whether Congress renews the Price-Anderson Act. The renewal of Price-Anderson, however, would be important for any new plants to be licensed in the future. Although several bills proposing the renewal of the Price-Anderson Act are

currently pending in the United States Congress, Generation is unable to predict at this time whether renewal will occur before August 1, 2002.

We maintain property insurance for each nuclear power plant in which we have an ownership interest. We are responsible for our proportionate share of premiums for such insurance based on our ownership interest. Our insurance policies provide coverage for decontamination liability expense, premature decommissioning and loss or damage to nuclear facilities. These policies require that insurance proceeds first be applied to assure that, following an accident, the facility is in a safe and stable condition and can be maintained in such condition. Under our insurance policies, proceeds not already expended to place the reactor in a stable condition must be used to decontaminate the facility. If, as a result of an incident, the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a decommissioning fund that we, or AmerGen, as the case may be, are required to maintain by the NRC. (See "Nuclear Facility Decommissioning.") These proceeds would be paid to the fund to make up any difference between the amount of money in the fund at the time of the early decommissioning and the amount that would have been in the fund if contributions had been made over the normal life of the facility. We are unable to predict what effect these requirements may have on the timing of the availability of insurance proceeds to creditors and the amount of these proceeds. Under the terms of the various insurance agreements, we could be assessed up to $121 million for losses incurred at any plant insured by the insurance companies.

Nuclear Electric Institute Limited (NEIL), a mutual insurance company to which Generation belongs, provides property and business interruption insurance for Generation's nuclear operations. One feature of our property insurance through NEIL is coverage for damages caused by acts of terrorism at any of our nuclear generating station. This terrorism endorsement to the NEIL policy specifies that its coverage applies to acts of terrorism similar to the September 11, 2001 events. In the event that one or more acts of terrorism cause accidental property damage within a 12-month period from the first accidental property damage under one or more policies for all insureds, the maximum recovery for all losses by all insureds will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity or any other source applicable to such losses. If total property losses exceed available funds under the policy, proportionate recovery is provided to cover a portion of an insured's property losses. The percentage recovery would be equal to the ratio of the insured's property losses and the total of all property losses.

Our insurance through NEIL also provides replacement power cost insurance in the event of a major accidental outage at a nuclear station. The policy provides for a waiting period before recovery of costs can commence. The premium for this coverage is subject to assessment for adverse loss experience, with a maximum assessment of $46 million per year. Recovery under this insurance for terrorist acts is subject to the $3.2 billion aggregate limit and is secondary to the property insurance described above.

In addition, we participate in the American Nuclear Insurers Master Worker Program, which provides coverage for worker tort claims filed for bodily injury caused by a nuclear energy accident. This program was modified, effective January 1, 1998, to provide coverage to all workers whose nuclear-related employment began on or after the commencement date of reactor operations. We will not be liable for a retroactive assessment under this new policy. However, in the event losses incurred under the small number of policies in the old program exceed accumulated reserves, a maximum retroactive assessment of up to $50 million could apply.

We do not carry business interruption insurance other than the NEIL coverage for nuclear operations. We are self-insured to the extent that any losses may exceed the amount of insurance maintained. Such losses could have a material adverse effect on our financial conditions and results of operations.

We currently have approximately 7,200 employees. Of those employees, 2,000 are subject to collective bargaining agreements with Local 15 of the International Brotherhood of Electrical Workers ("IBEW"). On April 20, 2001, Exelon and Local 15 officials signed an agreement for a new three-year collective bargaining agreement, effective April 1, 2001 through March 31, 2004. The new agreement covers our 2,000 employees. An agreement to extend the date of the contract was ratified by the union on December 31, 2001. For us, the new agreement extends the collective bargaining agreement through September 30, 2005.

We are involved in a number of judicial and regulatory proceedings (including the ones described below) concerning matters arising out of the conduct of our business. We believe, based on currently available information, that the ultimate outcome of any proceedings known to us at this time will not have a material adverse effect on our financial condition or results of operations.

Cotter Corporation. During 1989 and 1991, actions were brought in Federal and state courts in Colorado against ComEd and its subsidiary, Cotter Corporation ("Cotter"), seeking unspecified damages and injunctive relief based on allegations that Cotter permitted radioactive and other hazardous material to be released from its mill into areas owned or occupied by the plaintiffs, resulting in property damage and potential adverse health effects. In 1994, a Federal jury returned nominal dollar verdicts against Cotter on eight plaintiffs' claims in the 1989 cases, which verdicts were upheld on appeal. The remaining claims in the 1989 actions were settled or dismissed. In 1998, a jury verdict was rendered against Cotter in favor of 14 of the plaintiffs in the 1991 cases, totaling approximately $6 million in compensatory and punitive damages, interest and medical monitoring. On appeal, the Tenth Circuit Court of Appeals reversed the jury verdict, and remanded the case for new trial. These plaintiffs' cases were consolidated with the remaining 26 plaintiffs' cases, which had not been tried. The consolidated trial was completed on June 28, 2001. The jury returned a verdict against Cotter and awarded $16.3 million in various damages. On November 20, 2001, the District Court entered an amended final judgment which included an award of both pre-judgment and post-judgment interests, costs, and medical monitoring expenses which total $43.3 million. This matter is being appealed by Cotter in the Tenth Circuit Court of Appeals. Cotter will vigorously contest the award.

In November 2000, another trial involving a separate sub-group of 13 plaintiffs, seeking $19 million in damages plus interest was completed in federal district court in Denver. The jury awarded nominal damages of $42,500 to 11 of 13 plaintiffs, but awarded no damages for any personal injury or health claims, other than requiring Cotter to perform periodic medical monitoring at minimal cost. The plaintiffs appealed the verdict to the Tenth Circuit Court of Appeals.

On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability incurred by Cotter as a result of these actions, as well as any liability arising in connection with the West Lake Landfill discussed in the next paragraph.

The EPA has advised Cotter that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached barium sulfate at the site. Cotter, along with three other companies identified by the EPA as PRPs, is reviewing a draft feasibility study that recommends capping the site. The PRPs are also engaged in discussions with the State of Missouri and the EPA. The estimated costs of remediation for the site are $10 to $15 million. Once a final feasibility study is complete and a remedy selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. Until an agreement is reached, we cannot predict our share of the costs.

As a result of the restructuring of Exelon, we have agreed to assume the liability and obligation resulting from the Cotter matters.

Pennsylvania Real Estate Tax Appeals. PECO initiated tax appeals regarding two of its nuclear facilities, Limerick Generating Station (Montgomery County) and Peach Bottom Atomic Power Station (York County), and one of its fossil facilities, Eddystone (Delaware County). The potential benefit or obligation resulting from these appeals was transferred to us in connection with the restructuring of Exelon. We are also involved in a tax appeal for TMI (Dauphin County) through AmerGen. We do not believe the outcome of these matters will have a material adverse effect on our results of operations or financial condition.

Enron. We are an unsecured creditor in Enron Corp.'s bankruptcy proceeding. Our claim for power and other products sold to Enron in November and early December 2001 is $8.5 million. Enron may assert that we should not have closed out and terminated all of our forward contracts with Enron. If Enron is successful in this argument, our exposure could be greater than $8.5 million. We may also be subject to exposure due to credit policies of ISO-operated spot markets, such as ISO-New England and PJM, that allocate defaults of market participants to non-defaulting participants. We have established an allowance for uncollectibles for these matters.

Godley Park District. On April 18, 2001, the Godley Park District filed suit in Will County Circuit Court against ComEd and Exelon Corporation alleging that oil spills at Braidwood Station have contaminated the Park District's water supply. The complaint sought actual damages, punitive damages of $100 million and statutory penalties. The court dismissed all counts seeking punitive damages and statutory penalties, and the plaintiff has filed an amended complaint before the court. We are contesting the liability and damages sought by the plaintiff.

Exelon Ventures Company, LLC is our sole member and has control over all matters submitted for member approval and over our management and affairs. Exelon Ventures is wholly owned by Exelon. Currently some of our officers are also officers of Exelon or one of its subsidiaries other than Exelon Generation.

Name	Age	Position
Corbin A. McNeill, Jr.	62	Chief Executive Officer and President*
John W. Rowe	56	President and Co-Chief Executive Officer of Exelon**
Oliver D. Kingsley, Jr.	59	President and Chief Nuclear Office, Exelon Nuclear***
Ian P. McLean	52	President, Exelon Power Team
John L. Skolds	51	Chief Operating Officer, Exelon Nuclear****
William H. Bohlke	57	Sr. VP, Nuclear Services, Exelon Nuclear
Christopher M. Crane	43	Sr. VP, MidWest Regional Operating Group, Exelon Nuclear
Christine A. Jacobs	49	Sr. VP, Exelon Generation; President, Exelon Power
David W. Woods	44	Sr. VP, Communications & Public Affairs
John L. Settelen, Jr.	42	VP and Controller

Each of the executive officers named above, other than Mr. Kingsley, was elected to such office effective January 1, 2001, the effective date of the restructuring of Exelon. Mr. Kingsley was appointed to his position on March 1, 2002. Each of these executive officers holds such office at the discretion of the managing member of the Company until his or her replacement or earlier resignation, retirement or death. Other positions currently held by the executive officers with Exelon and prior positions held with Exelon, PECO, ComEd or other companies since January 1, 1996, are described below.

Corbin A. McNeill, Jr. Mr. McNeill is also Chairman and Co-Chief Executive Officer of Exelon. Prior to his election to his current position, Mr. McNeill was Chairman of the Board, President and Chief Executive Officer of PECO; President and Chief Executive Officer of PECO; and President and Chief Operating Officer and Executive Vice President—Nuclear of PECO. Mr. McNeill is also a director of Associated Electric and Gas Insurance Services Limited.

John W. Rowe. Mr. Rowe is Co-Chief Executive Officer and President of Exelon and a Director of PECO and ComEd. Prior to his election to his current position, Mr.Rowe was Chairman, President and Chief Executive Officer of ComEd and Unicom Corporation; and President and Chief Executive Officer of New England Electric System. Mr. Rowe is also a director of UnumProvident Corporation.

Oliver D. Kingsley, Jr. Mr. Kingsley is also an Executive Vice President of Exelon. Prior to his election to his current position, Mr. Kingsley was Executive Vice President of ComEd and Unicom

Corporation; President and Chief Nuclear Officer—Nuclear Generation Group of ComEd; and Chief Nuclear Officer of the Tennessee Valley Authority.

Ian P. McLean. Mr. McLean is also a Senior Vice President of Exelon. Prior to his election to his current position, Mr. McLean was President of the Power Team division of PECO; and Group Vice President of Engelhard Corporation.

John L. Skolds. Prior to his election to his current position, Mr. Skolds was Senior Vice President of Unicom Corporation; and President and Chief Operating Officer, South Carolina Electric and Gas Company. Mr. Skolds is also the Chief Executive Officer of AmerGen.

William H. Bohlke. Prior to his election to his current position, Mr. Bohlke was Vice President, Nuclear Engineering for Exelon; Vice President, Engineering of ComEd; Vice President and Director of Nuclear Power Operations of Stone & Webster Engineering Corporation; and Vice President, Nuclear Engineering of Florida Power & Light Company.

Christopher M. Crane. Prior to his election to his current position, Mr. Crane was Senior Vice President of ComEd; Vice President of ComEd; and Vice President of Tennessee Valley Authority.

Christine A. Jacobs. Prior to her election to her current position, Ms. Jacobs was Vice President, Support Services for PECO and Vice President, Industrial Operations, Americas for Rhone-Poulenc Rorer Pharmaceuticals.

David W. Woods. Mr. Woods is also a Senior Vice President of Exelon. Prior to his election to his current position, Mr. Woods was Senior Vice President—Corporate Public Affairs of PECO; and Chief of Staff of the Pennsylvania Senate Majority Leader.

John L. Settelen, Jr. Prior to his election to his current position, Mr. Settelen was Generation Business Unit Manager—Accounting and Control/Controller of PECO; and Vice President and Comptroller of New Jersey—American Water Company, Inc.

The Management Incentive Compensation Plan (the "MICP") was originally established by PECO in 1988 and amended in 1997. In connection with the merger, Exelon assumed sponsorship of the MICP.

The MICP provides for annual awards of cash, stock, or other currency (the "Awards") to key employees (employees so designated by a Committee of Exelon's Board of Directors, including employees who are officers or directors) based on achievement of certain pre-established goals. The maximum annual Award payable to any participant is two million dollars.

The MICP is administered and interpreted by a Committee (the "Committee") consisting of two or more outside, non-employee directors of Exelon. The Committee has the full power to select the employees who will receive Awards under the MICP; determine the amounts and forms of Awards; determines the terms and conditions of Awards in a manner consistent with the MICP; construe and interpret the MICP and any agreement or instrument entered into under the MICP; make factual determinations; and, establish, amend, or waive rules and regulations for the MICP's administration.

In order to qualify as performance-based compensation, the Committee must establish performance goals and the formula for applying such goals in determining Awards (within 90 days after the commencement of the applicable performance period or before 25% of the performance period has elapsed, if shorter than 12 months). During the performance period, the Committee may modify performance goals or the formula for applying such goals; provided, however, that the Committee cannot increase the Award otherwise payable to employees subject to section 162(m) of the Internal

Revenue Code under the goals and formula initially adopted. The Committee may, however, reduce or eliminate the Award otherwise payable.

The performance goals are based on business criteria chosen by the Committee from among the following alternatives, each of which may be based on absolute standards or peer industry group comparatives and may be applied at various organizational levels (e.g. corporate, business unit, division): a) total shareholder return; b) stock price increase; c) dividend payout as percentage of net income; d) return on equity; e) return on capital; f) cash flow, including operating cash flows, free cash flow, discounted cash flow return on investment, and cash flow in excess of cost of capital; g) economic value added (income in excess of capital costs); h) cost per kilowatt hour; i) market share; j) customer/employee satisfaction as measured by survey instruments; k) earnings per share; l) revenue; m) workforce diversity; n) safety; o) personal performance; p) productivity measures; q) diversification of business opportunities; r) price to earnings ratio: s) expense ratio; t) total expenditures; and u) completion of key projects.

The Exelon Long-Term Incentive Plan (the "Incentive Plan") was originally established by PECO in 1989 as the PECO Energy Company 1989 Long-Term Incentive Plan. In connection with the exchange of PECO shares for shares of Exelon Corporation and the merger, Exelon Corporation assumed sponsorship of the Incentive Plan and the Incentive Plan was amended to change its name and otherwise reflect the share exchange and the merger.

Employees of Exelon Corporation and its subsidiary companies (including us) are eligible to be selected to participate in the Incentive Plan. Approximately 650 persons are eligible to participate in the Incentive Plan.

The Incentive Plan authorizes the following types of grants singly, in combination or in tandem:

Stock Options. Grants consist of options to purchase shares of Exelon Corporation's common stock, which may be "incentive stock options" or non-qualified stock options. Incentive stock options must meet the requirements of Section 422 of the Internal Revenue Code and carry some potential tax advantages for the recipient. Non-qualified stock options are not subject to those requirements and do not carry such advantages. Each stock option grant specifies the number of shares subject to the option, the manner and time of the option's exercise and the exercise price per share of stock subject to the option. The exercise price of stock option may not be less than the fair market value of a share of Exelon Corporation common stock on the date the option is granted. The exercise price of an option may be paid by a participant in cash, shares of Exelon Corporation common stock owned by the participant if approved by Exelon's Compensation Committee, a combination thereof or such other consideration as the Compensation Committee may deem appropriate.

Stock Appreciation Rights. A stock appreciation right ("SAR") is a right to receive a payment (either in cash, shares of Exelon Corporation common stock, or a combination thereof) equal to the appreciation in market value of a stated number of shares of Exelon Corporation common stock. The appreciation is measured by the difference between a base amount stated in the SAR and the market value of a share of Exelon Corporation common stock on the date of exercise of the SAR. A SAR may be granted in tandem with a stock option ("Tandem SARS") or independent of a stock option ("Non-tandem SARs"). A Tandem SAR may be granted either at the time of the grant of the related stock option or, in the case of a non-qualified stock option, at any time thereafter during the term of such option. Upon the exercise of a stock option as to some or all of the shares covered by the award, the related Tandem SAR is cancelled automatically to the extent that the number of shares subject to the Tandem SAR exceeds the number of remaining shares subject to the related stock option.

Restricted Stock. Grants are made of restricted shares of Exelon Corporation common stock. Such grants will be subject to such terms, conditions, restrictions and/or limitations, if any, as Exelon's

Compensation Committee deems appropriate, which may include vesting periods, restrictions on transferability and requirements of continued employment.

Performance Shares and Performance Units. Performance shares are shares of Exelon Corporation common stock and performance units which are valued by reference to criteria chosen by Exelon's Compensation Committee. Such grants are contingent on the attainment over a specified period of time of certain performance objectives. The length of the performance period, the performance objectives to be achieved and the measure of whether and to what degree such objectives have been achieved are determined by Exelon's Compensation Committee. Amounts earned under performance shares and performance units may be paid in cash, shares of Exelon Corporation common stock or both.

Phantom Stock. Phantom stock is a grant expressed in terms of, but not actually represented by, a number of shares of Exelon Corporation common stock. Exelon's Compensation Committee establishes the initial value of the phantom stock at the time of grant, which may be greater than, equal to or less than the fair market value of a share of Exelon Corporation common stock. Exelon's Compensation Committee also determines the time at which the phantom stock will be paid and whether such payment will be in the form of cash, shares of Exelon Corporation common stock or a combination of both. Any cash payment will be the fair market value of shares of Exelon Corporation common stock on the payment date equal in number to the number of shares of phantom stock being paid in cash.

Dividend Equivalents. Each dividend equivalent represents the right to receive an amount in cash, or in shares of Exelon Corporation common stock having a fair market value, equal to the amount of each dividend paid on one share of Exelon Corporation common stock during a period of time established by Exelon's Compensation Committee. Dividend equivalents may be paid currently or accrued as contingent cash obligations payable at a time or times specified by Exelon's Compensation Committee. Dividend equivalents may be granted separately or in connection with grants of stock options or phantom stock under the Incentive Plan.

The Incentive Plan currently limits the maximum aggregate number of shares of Exelon Corporation common stock that may be granted to any given individual in any calendar year to 500,000 (proposed to be amended to 1,000,000). The proposed amendment also adds to the Incentive Plan a provision that limits the number of shares available to be granted under the Incentive Plan at full value as restricted stock, performance shares or phantom stock to 3,000,000.

Grants are evidenced by written agreements containing the terms, conditions, restrictions and/or limitations covering the grant.

Available Shares and Outstanding Awards. On October 20, 2000, the effective date of the exchange of PECO shares for shares of Exelon Corporation common stock and the merger, 10,800,000 shares of Exelon Corporation common stock were available for grants under the Incentive Plan. Since then, grants covering 9,883,672 shares have been made under the Incentive Plan and grants covering 232,651 shares have expired or been forfeited, leaving approximately 1,148,979 shares of Exelon Corporation common stock available for future grants under the Incentive Plan as of March 1, 2002. Approval of the proposed amendment of the Incentive Plan will increase the number of shares available for future grants under the Incentive Plan to approximately 14,148,000. As of March 1, 2002, the market price of Exelon Corporation common stock was $50.52 per share.

The Exelon Corporation Employee Stock Purchase Plan (the "Purchase Plan") was adopted by the Board of Directors of Exelon Corporation on May 11, 2001 and became effective on June 1, 2001, subject to approval by the shareholders of Exelon Corporation in April 2002 at the annual meeting. If shareholders do not approve the Purchase Plan, it will cease to be effective on May 10, 2002.

Under the Purchase Plan, eligible employees of Exelon and designated subsidiaries including us may authorize their employers to withhold up to 10% of their regular base pay and to use those amounts to purchase shares of Exelon Corporation common stock. The Purchase Plan establishes four purchase periods beginning on January 1, April 1, July 1 and October 1 of each year. A participant's payroll deductions are accumulated and used to purchase shares of Exelon Corporation common stock as soon as practicable after the end of each purchase period. The purchase price per share for any purchase period is equal to 90% of the lesser of the closing price on the New York Stock Exchange of a share of Exelon Corporation common stock on the first day of the purchase period or the last day of the purchase period on which the Exchange is open. Dividends on shares purchased under the Purchase Plan will be paid in cash unless the participant elects to have the dividends reinvested to purchase additional shares of Exelon Corporation common stock. Shares purchased with reinvested dividends will be purchased at fair market value with no discount. In addition to the 10% limit on payroll deductions, a participant in the Purchase Plan may not purchase more than 125 shares in any purchase period (500 shares per year) or more than $25,000 in fair market value of stock in any calendar year. An individual's purchases under the Purchase Plan also will be limited if they would cause the employee to own 5% or more of the total combined voting power or value of all classes of stock of Exelon Corporation or any of its subsidiaries.

Under the terms of the Purchase Plan, the maximum number of shares of Exelon Corporation common stock that may be purchased under the Purchase Plan is 3,000,000, subject to adjustment for stock dividends, stock splits or combinations of shares of Exelon Corporation common stock. Through the purchase period that ended December 31, 2001, 137,648 shares of Exelon Corporation common stock had been purchased under the Purchase Plan. John Rowe, President and Chief Executive Officer of our parent has purchased 394 shares under the Purchase Plan. As of March 31, 2002, approximately 28,705 employees were eligible to participate in the Purchase Plan and 3,657 were participating in the Purchase Plan.

In 2001, Exelon adopted a cash balance pension plan. All management and electing union employees who joined Exelon or one of its participating subsidiaries, including us, during 2001 become participants in the plan. Management employees who were active participants in Exelon's previous qualified defined plans at December 31, 2000 and are employed by Exelon in January 1, 2002 will be given a choice to convert to the cash balance plan. Participants in the cash balance plan, unlike participants in the other defined benefit plans, may request a lump-sum cash payment upon employee termination which may result in increased requirements for pension plan assets. Exelon may be required to increase future funding to the pension plan as a result of these increased cash requirements.

The "grant date present values" indicated in the option grant table below are an estimate based on the Black-Scholes option pricing model. Although executives risk forfeiting these options in some circumstances, these risks are not factored into the calculated values. The actual value of these options will be determined by the excess of the stock price over the exercise price on the date that the options are exercised. There is no certainty that the actual value realized will be at or near the value estimated by the Black-Scholes option pricing model. The assumptions used for the Black-Scholes model are as of December 31, 2001 and are as follows: Risk-free interest rate: 4.85%; Volatility: 37.17%; Dividend Yield: 3.24%; Time of Exercise: 5 years.

This table shows the number and value of exercised and unexercised stock options for the named executive officers during 2001. Value is determined using the market value of Exelon common stock at the year-end price of $47.88 per share, minus the value of Exelon common stock at the exercise price. All options whose exercise price exceeds the market value are valued at zero.

				Number of Securities Underlying Unexercised Options at 12/31/2001		Value of Unexercised In-the-Money Options at 12/31/2001
Name	Shares Acquired of Exercise (#)	Value Realized ($)		(#) Exercisable Unexercisable		($) Exercisable Unexercisable
Corbin A. McNeill, Jr.	32,500	$	1,478,750		545,833 E 494,967 U		$ $	11,586,765 E 886,265 U
John W. Rowe	100,000	$	2,980,000		348,000 E 525,100 U		$ $	2,936,529 E 1,058,110 U
Oliver D. Kingsley, Jr.	0		0		156,750 E 161,500 U		$ $	1,247,315 E 550,560 U
John L. Skolds	0		0		36,167 E 72,333 U			1,045 E 2,090 U
Ian P. McLean	0		0		110,999 E 97,001 U			883,356 E 547,369 U

The following tables show the estimated annual retirement benefits payable on a straight-life annuity basis to participating employees, including officers, in the earnings and year of service classes indicated, under Exelon's non-contributory retirement plans. Effective January 1, 2001, Exelon Corporation assumed sponsorship of the Commonwealth Edison Company Service Annuity System and the PECO Energy Company Service Annuity Plan. Effective December 31, 2001, these plans were merged to form the Exelon Corporation Retirement Program, which incorporates the separate benefit formula of each merged plan for employees in business units formerly covered by that merged plan. Effective January 1, 2001, Exelon Corporation also established two cash balance pension plans which cover management employees and bargaining unit employees hired on or after such date. The amounts shown in the table are not subject to any deduction for Social Security or other offset amounts.

Covered compensation includes salary and bonus which is disclosed in the Summary Compensation Table on page 66 for the named executive officers. The calculation of retirement benefits under the plans is based upon average earnings for the highest consecutive five-year period under the PECO Energy Company Service Annuity Benefit Formula and for the highest four-year period (three-year for certain represented employees) under the ComEd Service Annuity Benefit Formula.

The Internal Revenue Code limits the annual benefits that can be paid from a tax-qualified retirement plan to $170,000 as of January 1, 2001. As permitted by the Employee Retirement Income Security Act of 1974, Exelon sponsored supplemental plans, which allow the payment out of its general assets, any benefits calculated under provisions of the applicable retirement plan which may be above these limits.

	Annual Normal Retirement Benefits After Specified Years of Service
Highest 5-Year Average Earnings	10 Years ($)	15 Years ($)	20 Years ($)	25 Years ($)	30 Years ($)	35 Years ($)	40 Years ($)
$100,000.00	19,272	26,407	33,543	40,679	47,815	54,950	62,086
200,000.00	39,772	54,657	69,543	84,429	99,315	114,200	129,086
300,000.00	60,272	82,907	105,543	128,179	150,815	173,450	196,086
400,000.00	80,772	111,157	141,543	171,929	202,315	232,700	263,086
500,000.00	101,272	139,407	177,543	215,679	253,815	291,950	330,086
600,000.00	121,772	167,657	213,543	259,429	305,315	351,200	397,086
700,000.00	142,272	195,907	249,543	303,179	356,815	410,450	464,086
800,000.00	162,772	224,157	285,543	346,929	408,315	469,700	531,086
900,000.00	183,272	252,407	321,543	390,679	459,815	528,950	598,086
1,000,000.00	203,772	280,657	357,543	434,429	511,315	588,200	665,086

Mr. McNeill and Mr. McLean have 32 and 0 credited years of service, respectively, under PECO Energy Company's pension program.

	Annual Normal Retirement Benefits After Specified Years of Service
Highest 4-Year Average Earnings	10 Years ($)	15 Years ($)	20 Years ($)	25 Years ($)	30 Year ($)	35 Years ($)	40 Years ($)
$100,000.00	19,523	31,016	41,648	51,626	61,113	70,232	79,076
200,000.00	39,647	63,290	85,181	105,720	125,221	143,923	162,013
300,000.00	59,770	95,563	128,714	159,815	189,328	217,613	244,949
400,000.00	79,893	127,836	172,247	213,909	253,435	291,303	327,885
500,000.00	100,017	160,109	215,780	268,003	317,543	364,994	410,822
600,000.00	120,140	192,383	259,313	322,097	381,650	438,684	493,758
700,000.00	140,263	224,656	302,846	376,191	445,757	512,375	576,694
800,000.00	160,386	256,929	346,379	430,286	509,864	586,065	659,630
900,000.00	180,510	289,202	389,912	484,380	573,972	659,755	742,567
1,000,000.00	200,633	321,476	433,445	538,474	638,079	733,446	825,503

The approximate number of years of credited service under ComEd's pension programs for the persons named in the Summary Compensation Table are as follows: John W. Rowe, 24 years; Oliver D. Kingsley, 20 years; and John L. Skolds, 2 years.

Exelon entered into an amended employment agreement with Mr. Rowe, which amended and restated his employment agreement with Unicom Corporation and ComEd in effect at the time of the merger forming Exelon (the "prior agreement") and under which Mr. Rowe will serve as:

Mr. Rowe will succeed to the position of sole chief executive officer of Exelon or chairman of the Exelon board of directors if:

Mr. Rowe will receive an annual base salary determined by Exelon's compensation committee. Mr. Rowe will be eligible to participate in annual incentive award programs, long-term incentive plans and stock option plans on the same basis as other senior executives of Exelon. The agreement provided that a grant of options would be considered at the time the merger was completed. Mr. Rowe is entitled to participate in all savings, deferred compensation, retirement and other employee benefit plans generally available to other senior executives of Exelon. During the transition period, Mr. Rowe's base salary and participation in the plans and awards described in this paragraph will be in an amount or on a basis that is not less than that of Mr. McNeill's or on which Mr. McNeill participates.

Under his amended employment agreement and the prior agreement, Mr. Rowe is entitled to receive a special supplemental executive retirement plan, or SERP, benefit if he terminates due to normal retirement, early retirement, termination without cause, termination for good reason, death or disability or if he voluntarily terminates his employment for any other reason.

The term "good reason" includes the failure to appoint Mr. Rowe to the management and Exelon board of director positions described above. The special SERP benefit will equal the SERP benefit that Mr. Rowe would have received if:

Except as provided in the next paragraph, if Exelon terminates Mr. Rowe's employment for reasons other than cause, death or disability or if he should terminate employment for good reason on or after December 31, 2004 and not within 24 months following a change in control of Exelon, he would be entitled to the following benefits:

Mr. Rowe will receive the termination benefits described in "Change in Control and Severance Arrangements" below, rather than the benefits described in the previous paragraph, if Excelon terminates Mr. Rowe without cause or he terminates with good reason and

Although Exelon has not entered into an employment agreement with Mr. McNeill, the merger agreement provided that at any time during the transition period when Messrs. McNeill and Rowe are co-chief executive officers, each of them will receive the same salary, bonus and other compensation (including option grants and other incentive awards and all other forms of compensation) and enjoy the same other benefits and the same employment security arrangements as the other. In February 2002, Mr. McNeill announced that he will retire as an officer and director of Exelon effective immediately after the 2002 annual meeting of shareholders. Under an agreement approved by the board of directors of Exelon, Mr. McNeill will receive the termination benefits described in "Change in Control Severance Arrangements" below upon his retirement.

ComEd entered into an employment agreement with Oliver D. Kingsley, Jr. pursuant to which he became Executive Vice President and President and Chief Nuclear Officer-Nuclear Generation Group, effective November 1, 1997. The agreement provides for a guaranteed increase in annual base salary of at least 4% per year, beginning in 1999.

Mr. Kingsley received an option to purchase 25,000 shares of common stock with an option price equal to the fair market value of the common stock as of November 1, 1997. Such option became exercisable in equal installments on November 1 of 1998, 1999 and 2000, and expires on October 31, 2007. Mr. Kingsley also received a grant of 20,000 shares of restricted stock that vested in equal installments on November 1 of 1998, 1999 and 2000.

Mr. Kingsley received $375,000 as an inducement to enter into the employment agreement, and an annual living cost allowance equal to $75,000 (increased by the amount of applicable taxes on such amount as so increased) for the first three years of the agreement term.

Mr. Kingsley's employment agreement provides for a retirement benefit equal to the amount that would have been payable under the Service Annuity System (plus amounts payable under the ComEd Supplemental Management Retirement Plan) for an employee who retires at age 60 calculated based on the assumption that Mr. Kingsley had completed 15 years of credited service beginning with the third year of his employment and that such credited service increased by five years during each of the next two years, in addition to his actual years of credited service after five years of employment.

The employment agreement with Mr. Kingsley provides for a lump sum severance payment to Mr. Kingsley if he should be terminated without cause equal to two times his base salary at the time of such termination, and a continuation of health and life insurance benefits for two years after the date of termination, plus retirement benefits (calculated as though he had completed at least 15 years of credited service if such termination occurs during the first two years of employment) and retiree health care coverage. In addition, any unvested-portion of the restricted stock granted under the agreement will immediately become fully vested and nonforfeitable. These benefits have been incorporated into a

change in control severance agreement that became effective on October 20, 2000. See "Change in Control Severance Agreements" below.

Mr. Kingsley agreed not to use for his own benefit or disclose any confidential information of Unicom or ComEd during or after the term of his employment, and not to solicit any employee of ComEd for one year after the term of his employment with ComEd.

Exelon has entered into change in control agreements with certain senior executives including the senior executives listed under "Management" on page 61 which generally protect executives' positions and compensation levels through October 20, 2002 with respect to the Exelon merger in the case of certain officers, and for two years after certain future changes in control if such changes in control occur before June 1, 2003. The June 1, 2003 date is subject to annual extension if there is no change in control before June 1 of each year. In some cases, these agreements replaced change in control agreements with PECO and Unicom which became effective upon the completion of the merger and which cover employment through October 20, 2002. A material adverse change in compensation or position is included in the definition of "good reason" for purposes of these agreements. If an executive resigns for good reason or if the executive's employment is terminated by Exelon other than for cause, severance pay and benefits become payable.

The severance payments and benefits provided under the change in control agreements include:

Pursuant to the terms of offers of employment or employment agreements, certain employees are also entitled to additional service credits for purposes of retiree health care eligibility and for determining benefits under the supplemental retirement plan or arrangement in which they participate.

In connection with the severance benefits described above, each executive is subject to a non-compete agreement for 24 months from the applicable termination date. Although a participating employee does not have a duty to mitigate the amounts due from Exelon continued welfare benefit coverage would be offset during the applicable continuation period by comparable coverage provided under welfare plans of another employer.

Employees who are senior vice-presidents or above will receive an additional payment to cover excise taxes imposed under Section 4999 of the Internal Revenue Code on "excess parachute payments" or under similar state or local law if the after-tax amount of payments and benefits subject to these taxes exceeds 110% of the "safe harbor" amount that would not subject the employee to these excise taxes. If the after-tax amount, however, is less than 110% of the safe harbor amount, payments and benefits subject to these taxes would be reduced or eliminated to equal the safe harbor amount. Benefits payable to other employees subject to the excise taxes imposed under Section 4999 of the Internal Revenue Code will be reduced to the employees' safe harbor amount.

We are an indirect subsidiary of Exelon. The following describes our material relationships and agreements with Exelon and other affiliates.

Restructuring and Asset Transfers. During January 2001, Exelon undertook a restructuring to separate its generation and other competitive businesses from its regulated energy delivery business. As part of this restructuring, both ComEd and PECO transferred their assets and liabilities unrelated to energy delivery to other subsidiaries of Exelon, including us. In the case of ComEd, the assets and liabilities transferred to us included nuclear generation facilities, wholesale power marketing operations, rights under certain power purchase agreements and nuclear decommissioning trust funds. In the case of PECO, the assets and liabilities transferred related to nuclear, fossil and hydroelectric generation facilities and wholesale power marketing operations, rights under certain power purchase agreements and nuclear decommissioning trust funds. The liabilities that we assumed include: decommissioning costs for nuclear facilities; obligations to comply with all liabilities connected with or arising out of permits, licenses, exemptions, allowances, approvals and other items obtained or required in connection with the generation assets; obligations and liabilities arising under contracts assigned to us, including power purchase agreements and pollution control revenue bonds after January 1, 2001; all employment related obligations and liabilities to employees of PECO and ComEd who became our employees in connection with the restructuring; and certain litigation matters described under "Our Business—Litigation."

Power Purchase and Related Agreements with ComEd. We are a party to a power purchase agreement and other agreements with ComEd, under which we must provide ComEd with all of ComEd's energy, capacity and ancillary services needs through December 31, 2004 (after taking into account deliveries from other suppliers of electricity and capacity that ComEd is required to accept by law). ComEd uses such energy, capacity and ancillary services to meet its service obligations to its retail and wholesale customers and to provide energy imbalance service as part of its obligation to operate the ComEd control area. During the period from January 1, 2005 to December 31, 2006, the agreement changes to a partial requirements arrangement under which we will provide ComEd with all of the electric energy and capacity from the nuclear facilities formerly owned by ComEd that we now own and operate. Through 2004, ComEd has agreed to pay us fixed energy prices only, which vary depending on the time of day and the season. The prices for the portion of the term during 2005 and 2006 are not specified in the agreement, but the agreement does provide that the parties will meet before the end of 2004 to set the prices for that period, and that the intent is that such prices will reflect expected market prices for energy and capacity during that period. The agreement provides that if we and ComEd cannot agree on prices by July 1, 2004 (or by any agreed to later date), then ComEd may terminate the agreement as of December 31, 2004. We have also entered into an Ancillary Services and other Control Area Services Resource Purchase Agreement with ComEd. This agreement contains additional terms under which we provide ancillary and related services to ComEd.

Power Purchase Agreement with PECO. The power purchase agreement between PECO and us, dated January 1, 2001, requires us to deliver energy to PECO to meet PECO's hourly load obligations for provider-of-last-resort ("PLR") customers and provide PECO with rights to capacity sufficient to meet PECO's daily unforced capacity obligation as determined by PJM through the year 2010. To ensure long-term generation reliability within the PJM control area, PJM rules require that load-serving entities, such as PECO, have rights to capacity in amounts based on PECO's load plus a reserve margin. The bundled price for both the energy and capacity that we provide to PECO is a function of the amount PECO is able to charge its PLR customers. PECO arranges for transmission service and all other transmission service products with PJM and pays PJM for these services.

Power Purchase Agreements with AmerGen. A power purchase agreement between us and AmerGen, dated as of December 5, 2001, requires us to buy all unforced capacity associated with TMI, all electric output of TMI in excess of the output used to operate TMI and the output used to deliver electric energy to the point of delivery to us and all ancillary products that are derived from TMI, including but not limited to ancillary services, at a monthly all-in scheduled price that varies month to month over the term of the contract. The term of the contract is from January 1, 2002 to December 31, 2014. Under the terms of a 1999 power purchase agreement with AmerGen, we purchase all of the residual energy from Clinton through December 31, 2002, also at an all-in price that varies month to month over the term of the agreement. Currently the residual output approximates 25% of the total output for Clinton.

Market Operations Services Arrangement. As a generator connected to the regional transmission system controlled by PJM, we are obligated to conduct certain market operation services, which, prior to PECO's restructuring, were performed by PECO directly. Pursuant to the terms of a Market Operations Services Arrangement, PECO has agreed to continue to provide us with these services, which include, among other things, operation of generation dispatch function, troubleshooting generation problems and scheduling of generation units outages. For 2001, our cost was approximately $1.4 million for employee services under this arrangement. In addition to charges for employee services, we are charged for those costs, properly allocable to us, associated with the use of PECO-owned facilities and/or equipment (e.g., telecommunications equipment) in the performance of the market operations services under the terms of the agreement. The agreement can be terminated by either party upon 120 day's prior written notice.

Interconnection Agreements. Following the corporate restructuring and the disaggregation of Exelon's distribution and generation businesses, interconnection agreements between ComEd and us and between PECO and us were filed with FERC to establish the requirements, terms and conditions for the continuing interconnection of the generation facilities assigned to us with the transmission and distribution systems owned and operated by each of PECO and ComEd. The agreements govern interconnection only and it is our responsibility or the responsibility of the purchaser of our capacity or energy output to make arrangements for transmission service.

Generation Reliability Services. Pursuant to the terms of certain Call Contracts for Generator Reliability Services between us and PECO dated as of January 10, 2001, we have agreed that, when called upon by PECO to do so in accordance with the terms of the Call Contracts, we will generate energy at the Delaware Generation Station and Moser Generator and deliver that energy to PECO's distribution system in order to preserve the reliable operations of the distribution system. In exchange for providing such services, we are entitled to receive our net out-of-pocket costs associated with providing the services. The agreements are for terms of ten years, unless terminated earlier by either party upon 90 days' prior written notice, and relate to the Delaware Generation Station and the Moser Generation Station.

Transmission Services. We purchase transmission services from our affiliates at price terms set under FERC open-access transmission tariffs. For 2001, our affiliated transmission purchases totaled $6.6 million.

Operating Guidelines and License Agreement. In connection with the corporate restructuring of ComEd, ComEd transferred to us two synchronous condensers and related equipment located at Zion Nuclear Station. These synchronous condensers are used to provide voltage support on ComEd's transmission system. Pursuant to the terms of the Operating Guidelines and License Agreement, we license to ComEd all of our rights to the synchronous condensers and agree to operate and maintain the synchronous condensers as required by ComEd.

AmerGen Services Agreement. We provide operation and support services to the nuclear facilities owned by AmerGen pursuant to a Services Agreement dated as of March 1, 1999. The Services Agreement has an indefinite term and may be terminated by us or by AmerGen on 90 days' notice. Under work orders issued under the Services Agreement, we provide such services as administrative and management services, human resource services, legal services, financial and accounting services, information technology and computer services and laboratory analysis services. We are compensated for these services in an amount agreed to in the work order but not less than the higher of our fully allocated costs for performing the services or the market price. In 2001, we charged AmerGen $80 million for these services.

Agreement with Exelon Energy Company, LLC. Under a power purchase agreement between Exelon Energy Company, LLC ("Exelon Energy") and us for the period January 1, 2001 through March 31, 2003, we are obligated to provide all the energy and capacity requirements of Exelon Energy to enable Exelon Energy to fulfill its competitive retail load obligations in Massachusetts at market-based prices. Exelon Energy is an affiliate of Exelon that provides competitive retail generation service to customers in the PJM region and elsewhere.

Capital Contributions and Distributions. The total capital contributions to us from Exelon in connection with the transfer and purchase of operating assets were $2.398 million in 2001. Exelon has not contributed any capital to us in 2002. There are currently no plans for us to make distributions to Exelon.

Affiliated Services Agreements. There are several contracts among Exelon and its affiliates, including us, under which services are provided and received. Exelon Business Services Company, a

wholly owned subsidiary of Exelon, provides business services, such as legal, accounting, purchasing and information technology, to Exelon and its affiliates, including us, at cost. ComEd and PECO currently provide services to or receive services from Exelon affiliates, including us, at market prices, or if there is no prevailing price, then at fully allocated cost. We also provide and receive from ComEd and PECO services, at cost, pertaining to the interface between the generation function conducted by us and the transmission and distribution functions provided by ComEd and PECO. These services are limited to those necessary for the efficient operation of the facilities located at the generation station sites where generation facilities are connected to the transmission and distribution facilities (primarily switchyard facilities). We also provide supply planning services, at cost, to ComEd and PECO and assist them in obtaining energy supply resources to the extent energy supply is not provided by us.

Pollution Control Notes. In 2001, PECO transferred to us $121 million of debt, through refundings of tax-exempt pollution control notes. We intend to assume from PECO approximately $29.5 million in debt through refundings in 2002.

Consolidated Tax Return and Tax Sharing Agreement. We join with Exelon and its subsidiaries in filing a consolidated federal income tax return. The consolidated tax liability is allocated among participants in accordance with a Tax Sharing Agreement entered into with the other members of the Exelon Consolidated Group (including PECO and ComEd). This agreement provides an equitable method for determining the share of the affiliated group's consolidated federal tax burdens and benefits to be attributed to each member.

In connection with the sale of the original notes, we entered into a registration rights agreement with the initial purchasers. Under the registration rights agreement, we agreed to use our best efforts to complete the exchange offer and to file and cause to become effective with the SEC a registration statement for the exchange of the original notes for exchange notes.

The terms of the exchange notes are the same as the terms of the original notes, except that the exchange notes have been registered under the Securities Act and will not be subject to some restrictions on transfer that apply to the original notes. In that regard, the original notes provide, among other things, that if the exchange offer has not been consummated within the period specified in the original notes, the interest rate on the original notes will increase by 0.50% per annum, until the exchange offer is consummated.

Upon completion of the exchange offer, holders of original notes will not be entitled to any further registration rights under the registration rights agreement, except under limited circumstances. See "Risk Factors—If you fail to exchange the original notes, they will remain subject to transfer restrictions" and "Description of the Exchange Notes." The exchange offer is not being made to holders of original notes in any jurisdiction in which the exchange offer or the acceptance of the notes would not comply with securities or blue sky laws.

The original notes were issued and are held in the book-entry system of The Depository Trust Company ("DTC"). Unless the context requires otherwise, the term "holder" with respect to the exchange offer means any person whose original notes are held of record by DTC and who desires to deliver such original notes by book-entry transfer at DTC. As soon as practicable after the Expiration Date, we will exchange the original notes for a like aggregate principal amount of the exchange notes of each series.

Completion of the exchange offer is subject to the conditions that the exchange offer not violate any applicable law or interpretation of the staff of the Division of Corporate Finance of the SEC and that no injunction, order or decree has been issued that would prohibit, prevent or materially impair our ability to proceed with the exchange offer. The exchange offer is also subject to various procedural requirements discussed below with which holders must comply. We reserve the right, in our absolute discretion, to waive compliance with these requirements subject to applicable law.

We are offering, upon the terms and subject to the conditions described in this prospectus and in the accompanying letter of transmittal, to exchange up to $700,000,000 aggregate principal amount of exchange notes for a like aggregate principal amount of original notes of the same series properly tendered on or before the Expiration Date and not properly withdrawn in accordance with the procedures described below. We will issue, promptly after the Expiration Date, an aggregate principal amount of up to $700,000,000 of exchange notes in exchange for a like principal amount of outstanding original notes tendered and accepted in connection with the exchange offer. We will pay all charges and expenses, other than certain applicable taxes described below, in connection with the exchange offer. See "—Fees and Expenses."

Holders may tender their original notes in whole or in part in minimum denominations of $1,000 and multiples thereof. The exchange offer is not conditioned upon any minimum principal amount of original notes being tendered. As of the date of this prospectus, $700,000,000 aggregate principal amount of the original notes is outstanding. Holders of original notes do not have any appraisal or dissenters' rights in connection with the exchange offer. Original notes that are not tendered or are tendered but not accepted in connection with the exchange offer will remain outstanding and be

entitled to the benefits of the indenture, but will not be entitled to any further registration rights under the registration rights agreement, except under limited circumstances. See "Risk Factors—If you fail to exchange the original notes, they will remain subject to transfer restrictions" and "Description of the Exchange Notes." If any tendered original notes are not accepted for exchange because of an invalid tender, the occurrence of other events described in this prospectus or otherwise, appropriate book-entry transfer will be made, without expense, to the tendering holder of the original notes promptly after the Expiration Date. Holders who tender original notes in connection with the exchange offer will not be required to pay brokerage commissions or fees or, subject to the instructions in the bondholders' instruction form, transfer taxes with respect to the exchange of original notes in connection with the exchange offer.

We do not make any recommendation to holders of original notes as to whether to exchange all or any portion of their original notes in the exchange offer. In addition, no one has been authorized to make any recommendation as to whether holders should exchange notes in the exchange offer. Holders of original notes must make their own decisions whether to exchange original notes in the exchange offer and, if so, the aggregate amount of original notes to exchange based on the holders' own financial positions and requirements.

The term "Expiration Date" means 5:00 p.m., Eastern Time, on , 2002. However, if the exchange offer is extended by us, the term "Expiration Date" will mean the latest date and time to which we extend the exchange offer.

We expressly reserve the right in our sole and absolute discretion, subject to applicable law, at any time and from time to time:

If the exchange offer is amended in a manner determined by us to constitute a material change, we will promptly

We will promptly notify the exchange agent by making an oral or written public announcement of any delay in acceptance, extension, termination or amendment. This announcement in the case of an extension will be made no later than 9:00 a.m., Eastern Time, on the next business day after the previously scheduled expiration date. Without limiting the manner in which we may choose to make any public announcement and, subject to applicable law, we will have no obligation to publish, advertise or otherwise communicate any such public announcement other than by issuing a release to an appropriate news agency.

Upon the terms and subject to the conditions of the exchange offer, we will exchange and issue to the exchange agent, promptly after the Expiration Date, exchange notes for original notes validly tendered and not withdrawn. In all cases, delivery of exchange notes in exchange for original notes tendered and accepted for exchange pursuant to the exchange offer will be made only after timely receipt by the exchange agent of:

The term "book-entry confirmation" means a timely confirmation of a book-entry transfer of original notes into the exchange agent's account at DTC. The term "agent's message" means a message, transmitted by DTC to and received by the exchange agent and forming a part of a book-entry confirmation, that states that DTC has received an express acknowledgment from the tendering DTC participant. This acknowledgment states that the participant has received and agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against the participant.

If the procedures for book-entry transfer cannot be completed on a timely basis or time will not permit all required documents to reach the Exchange Agent prior to 5:00 PM Eastern Standard Time on the Expiration Date, a Notice of Guaranteed Delivery may be submitted to the Exchange Agent in the manner and at the address for the Exchange Agent below (See "—Exchange Agent"). The notice of guaranteed delivery must be signed by a member of a registered national securities exchange, or a member of the National Association of Securities Dealers or a commercial bank or trust company having an office or correspondent in the United States, or an "eligible guarantor institution" within the meaning of Rule 17Ad-15 of the Securities Exchange Act of 1934, as amended. In addition, in order to use the guaranteed delivery procedure to render original notes pursuant to the Exchange Offer, a completed and signed and dated Letter of Transmittal (or facsimile thereof) must also be received by the Exchange Agent prior to 5:00 PM Eastern Standard Time on the Expiration Date.

Subject to the terms and conditions of the exchange offer, we will be deemed to have accepted for exchange, and therefore exchanged, original notes validly tendered and not withdrawn as, if and when we give oral or written notice to the exchange agent of our acceptance of such original notes for exchange pursuant to the exchange offer. The exchange agent will act as agent for us for the purpose of receiving tenders of original notes, letters of transmittal and related documents, and as agent for tendering holders for the purpose of receiving holders' instruction forms, letters of transmittal and related documents and transmitting exchange notes to validly exchanging holders. The exchange will be made promptly after the Expiration Date.

If, for any reason whatsoever, acceptance for exchange or the exchange of any tendered original notes is delayed, whether before or after our acceptance for exchange of original notes, or we extend the exchange offer or are unable to accept for exchange or exchange tendered original notes, then, without prejudice to the rights we have in the exchange offer, the exchange agent may, nevertheless, on our behalf and subject to Rule 14e-1(c) under the Exchange Act, retain tendered original notes. These original notes may not be withdrawn except to the extent tendering holders are entitled to withdrawal rights as described under "—Withdrawal Rights."

Under the letter of transmittal or agent's message, a holder of original notes will warrant and agree that it has full power and authority to tender, exchange, sell, assign and transfer original notes, that we will acquire good, marketable and unencumbered title to the tendered original notes, free and clear of all liens, restrictions, charges and encumbrances, and the original notes tendered for exchange are not subject to any adverse claims or proxies. The holder also will warrant and agree that it will, upon request, execute and deliver any additional documents deemed by us or the exchange agent to be necessary or desirable to complete the exchange, sale, assignment, and transfer of the original notes exchanged in the exchange offer.

Valid Tender. The tender of original notes must follow the procedures for book-entry transfer described below and a book-entry confirmation, including an agent's message if the tendering holder has not delivered a letter of transmittal, must be received by the exchange agent, in each case on or before the Expiration Date.

If less than all of the original notes are to be exchanged, a holder should fill in the amount of original notes being exchanged in the appropriate box on the holder's instruction forms. The entire amount of original notes will be deemed to have been tendered for exchange unless otherwise indicated.

The method of delivery of the holder's instruction form and all other required documents is at the option and sole risk of the tendering holder. Delivery will be deemed made only when actually received by the exchange agent. If delivery is by mail, we recommend properly insured registered mail, return receipt requested, or an overnight delivery service. In all cases, you should allow sufficient time to ensure timely delivery.

The exchange agent will establish an account with respect to the original notes at DTC for purposes of the exchange offer within two business days after the date of this prospectus. Any financial institution that is a participant in DTC's book-entry transfer facility system may make a book-entry delivery of the original notes by causing DTC to transfer the original notes into the exchange agent's account at DTC in accordance with DTC's procedures for transfers. However, although delivery of original notes may be effected through book-entry transfer into the exchange agent's account at DTC, the holder's instruction form (or facsimile thereof), properly completed and duly executed, or an agent's message instead of the letter of transmittal, and any other required documents, must in any case be delivered to and received by the exchange agent at its address listed under "—Exchange Agent" on or before the Expiration Date.

Delivery of documents to DTC in accordance with DTC's procedures does not constitute delivery to the exchange agent.

Determination of Validity. All questions as to the form of documents, validity, eligibility, including time of receipt, and acceptance for exchange of any tendered original notes will be determined by us, in our sole discretion. Our interpretation of the terms and conditions of the exchange offer, including the bondholders' instruction form letter of transmittal and the accompanying instructions, will be final and binding.

We reserve the absolute right, in our sole and absolute discretion, to reject any and all tenders determined by us not to be in proper form or the acceptance of which, or exchange for, may, in the opinion of our counsel, be unlawful. We also reserve the absolute right, subject to applicable law, to waive any condition or irregularity in any tender by a particular holder whether or not similar conditions or irregularities are waived in the case of other holders. No tender will be deemed to have been validly made until all irregularities with respect to such tender have been cured or waived. Neither we, any of our affiliates or assigns, the exchange agent nor any other person will be under any duty to give any notification of any irregularities in tenders or incur any liability for failure to give any notification.

If any bondholder instruction form, endorsement, bond power, power of attorney, or any other required document is signed by a trustee, executor, administrator, guardian, attorney-in-fact, officer of a corporation or other person acting in a fiduciary or representative capacity, that person should so indicate when signing, and unless waived by us, evidence satisfactory to us, in our sole discretion, of that person's authority must be submitted.

We are making the exchange offer in reliance on the position of the staff of the Division of Corporation Finance of the SEC as defined in certain interpretive letters addressed to third parties in other transactions. However, we did not seek our own interpretive letter and we cannot assure that the staff of the Division of Corporation Finance of the SEC would make a similar determination with respect to the exchange offer as it has in other interpretive letters to third parties. Based on these interpretations by the staff of the Division of Corporation Finance of the SEC, and subject to the two immediately following sentences, we believe that exchange notes issued pursuant to this exchange offer in exchange for original notes may be offered for resale, resold and otherwise transferred by a holder thereof (other than a holder who is a broker-dealer) without further compliance with the registration and prospectus delivery requirements of the Securities Act, provided that such exchange notes are acquired in the ordinary course of the holder's business and that the holder is not participating, and has no arrangement or understanding with any person to participate, in a distribution (within the meaning of the Securities Act) of the exchange notes.

However, any holder of original notes who is an "affiliate" of ours or who intends to participate in the exchange offer for the purpose of distributing exchange notes, or any broker-dealer who purchased original notes from us to resell pursuant to Rule 144A or any other available exemption under the Securities Act:

In addition, as described below, if any broker-dealer holds original notes acquired for its own account as a result of market-making or other trading activities and exchanges those original notes for exchange notes, then that broker-dealer must deliver a prospectus meeting the requirements of the Securities Act in connection with any resales of those exchange notes. Each holder of original notes who wishes to exchange original notes for exchange notes in the exchange offer will be required to represent that:

In addition, we may require the holder, as a condition to that holder's eligibility to participate in the exchange offer, to furnish to us (or an agent of ours) in writing, information as to the number of

"beneficial owners" (within the meaning of Rule 13d-3 under the Exchange Act) on behalf of whom that holder holds the original notes to be exchanged in the exchange offer.

Each broker-dealer that receives exchange notes for its own account in the exchange offer must acknowledge that it acquired the original notes for its own account as the result of market-making activities or other trading activities and must agree that it will deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of those exchange notes. The letter of transmittal states that by making that acknowledgement and delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. Based on the position taken by the staff of the Division of Corporation Finance of the SEC in the interpretive letters referred to above, we believe that participating broker-dealers who acquired original notes for their own accounts as a result of market-making activities or other trading activities may fulfill their prospectus delivery requirements with respect to the exchange notes received upon exchange of original notes (other than original notes that represent an unsold allotment from the initial sale of the original notes) with a prospectus meeting the requirements of the Securities Act, which may be the prospectus prepared for this exchange offer so long as it contains a description of the plan of distribution regarding the resale of the exchange notes.

Accordingly, this prospectus, as it may be amended or supplemented from time to time, may be used by a participating broker-dealer in connection with resales of exchange notes received in exchange for original notes where the original notes were acquired by the participating broker-dealer for its own account as a result of market-making or other trading activities. See "Plan of Distribution." Subject to certain provisions contained in the registration rights agreement, we have agreed that this prospectus, as it may be amended or supplemented from time to time, may be used by a participating broker-dealer in connection with resales of exchange notes for a period not exceeding one year after the expiration date. However, a participating broker-dealer who intends to use this prospectus in connection with the resale of exchange notes received in exchange for original notes pursuant to the exchange offer must notify us on or before the Expiration Date that it is a participating broker-dealer. This notice may be given in the space provided for that purpose in the letter of transmittal or may be delivered to the exchange agent at one of the addresses set forth herein under "—Exchange Agent."

Any participating broker-dealer who is an "affiliate" of ours may not rely on these interpretive letters and must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction. In that regard, each participating broker-dealer who surrenders original notes in the exchange offer will be deemed to have agreed, by execution of the letter of transmittal or an agent's message, that upon receipt of notice from us of the occurrence of any event or the discovery of:

that participating broker-dealer will suspend the sale of exchange notes under this prospectus until we have amended or supplemented this prospectus to correct the misstatement or omission and have furnished copies of the amended or supplemented prospectus to the participating broker-dealer, or we have given notice that the sale of the exchange notes may be resumed, as the case may be.

Except as otherwise provided in this prospectus, tenders of original notes may be withdrawn at any time on or before the Expiration Date. In order for a withdrawal to be effective, a written, telegraphic, telex or facsimile transmission of the notice of withdrawal must be timely received by the exchange agent at its address listed under "—Exchange Agent" on or before the Expiration Date. Any notice of withdrawal must specify the name of the person who tendered the original notes to be withdrawn and the aggregate principal amount of original notes to be withdrawn.

The notice of withdrawal must specify the name and number of the account at DTC to be credited with the withdrawal of original notes, in which case a notice of withdrawal will be effective if delivered to the exchange agent by written, telegraphic, telex or facsimile transmission. Withdrawals of tenders of original notes may not be rescinded. Original notes properly withdrawn will not be deemed validly tendered for purposes of the exchange offer, but may be retendered at any subsequent time on or before the Expiration Date by following any of the procedures described above under "—Procedures for Tendering Original Notes." All questions as to the validity, form and eligibility, including time of receipt, of withdrawal notices will be determined by us, in our sole discretion, and our determination will be final and binding on all parties. None of we, the exchange agent or any other person is under any duty to give any notification of any irregularities in any notice of withdrawal nor will those parties incur any liability for failure to give that notice. Any original notes that have been tendered but which are withdrawn will be credited to the holder promptly after withdrawal.

Interest on the exchange notes will accrue at the rate of 6.95% per annum and will be payable semi-annually in arrears on June 15 and December 15 of each year, commencing June 15, 2002. We will make each interest payment to the persons in whose names the exchange notes are registered at the close of business on the 15th day immediately preceding the applicable interest payment date. The exchange notes will bear interest from and including the last interest payment date on the original notes, or if one has not yet occurred, the date of issuance of the original notes. Accordingly, holders of original notes that are accepted for exchange will not receive accrued but unpaid interest on original notes at the time of tender. Rather, that interest will be payable on the exchange notes delivered in exchange for the original notes on the first interest payment date after the Expiration Date.

The exchange notes will be recorded at the same carrying value as the original notes for which they are exchanged, which is the aggregate principal amount of the original notes, as reflected in our accounting records on the date of exchange. Accordingly, no gain or loss for accounting purposes will be recognized in connection with the exchange offer. The cost of the exchange offer will be amortized over the term of the exchange notes.

Wachovia Bank, National Association has been appointed exchange agent for the exchange offer. Delivery of the bondholders' instruction forms, letters of transmittal and any other required documents, questions, requests for assistance, and requests for additional copies of this prospectus or of the

bondholders' instruction form or letters of transmittal should be directed to the exchange agent as follows:

Wachovia Bank, National Association
Exelon Generation Company, LLC
Corporate Actions Department
1525 West W.T. Harris Boulevard, 3C3
Charlotte, North Carolina 28262
Attention: Marsha Rice

Delivery to other than the above addresses or facsimile number will not constitute a valid delivery.

We have agreed to pay the exchange agent reasonable and customary fees for its services and will reimburse it for its reasonable out-of-pocket expenses. We will also pay brokerage houses and other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding copies of this prospectus and related documents to the beneficial owners of original notes, and in handling or tendering for their customers. Holders who tender their original notes for exchange will not be obligated to pay any transfer taxes in connection with the transfer. If, however, exchange notes are to be delivered to, or are to be issued in the name of, any person other than the registered holder of the original notes tendered, or if a transfer tax is imposed for any reason other than the exchange of original notes in connection with the exchange offer, then the amount of any such transfer taxes, whether imposed on the registered holder or any other persons, will be payable by the tendering holder. If satisfactory evidence of payment of such taxes or exemption therefrom is not submitted with the exchanging holder's letter of instruction or the letter of transmittal, the amount of such transfer taxes will be billed directly to such tendering holder. We will not make any payment to brokers, dealers or other nominees soliciting acceptances of the exchange offer.

We issued the original notes and will issue the exchange notes under the indenture dated as of June 1, 2001 (the "indenture") between us and Wachovia Bank, National Association, as trustee (the "trustee"). The indenture includes certain terms of the exchange notes and terms made part of the indenture by reference to the Trust Indenture Act of 1939, as amended (the "Trust Indenture Act"). You should refer to the indenture and the Trust Indenture Act for a statement of these terms. The indenture is governed by Pennsylvania law. As used herein, "notes" means original notes and exchange notes. The indenture provides for issuance from time to time of debt securities in series (including the notes) in an unlimited amount. We may issue additional securities under the indenture from time to time.

The following summary of selected provisions of the indenture is not complete. We recommend that you read the indenture, a copy of which may be obtained from the trustee. You can find the definitions of certain capitalized terms used in the following summary under the subheading "—Certain Definitions."

The exchange notes will be our unsecured obligations. They will rank equally in right of payment to all of our existing and future and unsecured and unsubordinated indebtedness. We have approximately $1.03 billion of indebtedness outstanding, all of which is senior unsecured debt. The exchange notes will rank junior to secured indebtedness to the extent of related collateral. We currently do not have any outstanding secured indebtedness.

The exchange notes will be unlimited in aggregate principal amount. The exchange notes initially will be issued in an aggregate principal amount of $700,000,000. We may, without the consent of the holders of the exchange notes, create and issue additional notes ranking equally with the exchange notes and otherwise similar in all respects so that such additional notes will be consolidated and form a single series with the exchange notes. No additional notes can be issued if an event of default exists with respect to the exchange notes.

The exchange notes will mature on June 15, 2011. Interest will be payable on the exchange notes semiannually on June 15 and December 15 of each year, commencing on June 15, 2002 until the principal is paid or made available for payment. The exchange notes will bear interest from and including the last interest payment date on the original notes. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.

For so long as the exchange notes are issued in book-entry form, payments of principal and interest will be made in immediately available funds by wire transfer to The Depository Trust Company ("DTC") or its nominee. If the exchange notes are issued in certificated form to a holder other than DTC, payments of principal and interest will be made by check mailed to the holder at the holder's registered address or, upon written application by a holder of $1,000,000 or more in aggregate principal amount of exchange notes to the trustee in accordance with the terms of the indenture, by wire transfer of immediately available funds to an account maintained by such holder with a bank or other financial institution. Payment of principal of the exchange notes will be made against surrender of such exchange notes at the office or agency of our company in New York, New York. Payment of interest on the exchange notes will be made to the person in whose name such exchange notes are registered at the close of business on the June 1 or December 1 immediately preceding the relevant interest payment date. Default interest will be paid in the same manner to holders as of a special record date established in accordance with the indenture.

All amounts paid by us for the payment of principal, premium (if any) or interest on any exchange notes that remain unclaimed at the end of two years after such payment has become due and payable will be repaid to us and the holders of such exchange notes will thereafter look only to us for payment thereof.

We may, at our option, redeem the exchange notes in whole or in part at any time at a redemption price equal to the greater of:

The redemption price will be calculated assuming a 360-day year consisting of twelve 30-day months.

We will mail notice of any redemption at least 30 days but not more than 60 days before the redemption date to each registered holder of the exchange notes to be redeemed.

Unless we default in payment of the redemption price, on and after the redemption date, interest will cease to accrue on the exchange notes or portions of the exchange notes called for redemption.

We will not consolidate with or merge with or into any other person, or sell, convey, transfer or lease our properties and assets substantially as an entirety to any person, and we will not permit any person to consolidate with or merge with or into us, unless:

Except for the sale of our properties and assets substantially as an entirety as described in "Mergers and Consolidations" above, and other than assets required to be sold to conform with governmental regulations, we will not consummate any Asset Sale, if the aggregate net book value of all Asset Sales consummated since the date of issuance of the exchange notes would exceed 25% of our consolidated net tangible assets as of the beginning of our most recently ended full fiscal quarter; provided that any such Asset Sale will be disregarded for purposes of this 25% limitation if the proceeds thereof (1) are, within 12 months of such Asset Sale, invested or reinvested by us in new generation assets or (2) are used by us to repay our Indebtedness.

We shall not issue, assume, guarantee or permit to exist any Indebtedness secured by any lien on any of our property, whether owned on the date that the exchange notes are issued or thereafter acquired without, in any such case, effectively securing the outstanding exchange notes (together with, if we shall so determine, any other Indebtedness of or guaranteed by us ranking equally with the original notes) equally and ratably with such Indebtedness (but only so long as such Indebtedness is so secured); provided, however, that the foregoing restriction does not apply to the following permitted liens:

If we propose to pledge, mortgage or hypothecate any property, other than as permitted by clauses (1) through (9) of the previous paragraph, we must (prior thereto) give written notice thereof to the trustee, who must give notice to the holders, and we must, prior to or simultaneously with such pledge, mortgage or hypothecation, effectively secure, all the exchange notes equally and ratably with such Indebtedness. The indenture does not otherwise limit our Subsidiaries ability to issue, assume, guarantee or permit to exist any Indebtedness secured by any lien on any of such Subsidiary's property, whether owned on the date the exchange notes are issued or thereafter acquired, provided that such Indebtedness is limited in recourse only to such Subsidiary.

We may not enter into any sale and leaseback transaction with any subsidiary. In addition, we may not enter into any sale and leaseback transaction unless we comply with this restrictive covenant. A "sale and leaseback transaction" generally is an arrangement between us and a subsidiary, bank, insurance company or other lender or investor where we lease real or personal property which was or will be sold by us to that subsidiary, lender or investor.

We can comply with this restrictive covenant if we meet either of the following conditions:

If an event of default (other than an event of default due to of our bankruptcy, insolvency or reorganization) occurs and is continuing, either the trustee or the holders of not less than 25% in aggregate principal amount of the notes outstanding under the indenture may, by written notice to us (and to the trustee if given by the holders), declare the principal of and accrued interest on all notes outstanding under the indenture to be immediately due and payable, but upon certain conditions such declaration may be annulled and past defaults (except, unless already cured, a default in payment of

principal, premium or interest) may be waived by the holders of a majority in aggregate principal amount of notes then outstanding under the indenture. If an event of default due to our bankruptcy, insolvency or reorganization occurs, all unpaid principal, premium, if any, and interest in respect of the notes outstanding under the indenture will automatically become due and payable without any declaration or other act on the part of the trustee or any holder.

The holders of a majority in principal amount of the notes then outstanding under the indenture shall have the right to direct the time, method and place of conducting any proceeding for any remedy available to the trustee under the indenture, subject to certain limitations specified in the indenture, provided that the holders offer to the trustee reasonable indemnity against expenses and liabilities.

Under the indenture, our rights and obligations and the rights of the holders of any notes may be changed. Any change affecting the rights of the holders of any series of notes requires the consent of the holders of not less than a majority in aggregate principal amount of the outstanding notes of all series affected by the change, voting as one class. However, we cannot change the terms of payment of principal or interest, or a reduction in the percentage required for changes or a waiver of default with respect to any note unless all the holders consent. We may take other action that does not affect the rights of the holders by executing supplemental indentures without the consent of any noteholders.

The indenture provides that we will be deemed to have paid and will be discharged from any and all obligations in respect of notes issued under the indenture, on the 91st day after the deposit referred to below has been made, and the provisions of the indenture will cease to be applicable with respect to the notes (except for, among other matters, certain obligations to register the transfer of or exchange of the notes, to replace apparently mutilated, defaced, destroyed, lost or stolen notes, to maintain paying agencies and to hold funds for payment in trust) if:

The indenture further provides that its provisions will cease to be applicable to (1) the covenants described under "Certain Covenants—Mergers and Consolidations," "—Limitations on Asset Sales," and "—Limitation on Liens" and (2) clause (4) under "Events of Default" with respect to such covenants and clauses (3) and (5) under "Events of Default" upon the deposit with the trustee, in trust, of money and/or U.S. Government Obligations that through the payment of interest and principal in respect thereof in accordance with their terms will provide money in an amount sufficient to pay the principal of, premium, if any, and accrued interest on the notes, the satisfaction of the conditions described in clauses (B)(2), (C) and (D) under "—Defeasance" above and the delivery by us to the trustee of an opinion of counsel to the effect that, among other things, the holders of the notes will not recognize income, gain or loss for federal income tax purposes as a result of the deposit and defeasance of certain covenants and events of default and will be subject to federal income tax on the same amount and in the same manner and at the same time as would have been the case if the deposit and defeasance had not occurred.

If we exercise our option to omit compliance with certain covenants and provisions of the indenture with respect to the notes as described in the immediately preceding paragraph and the notes are declared due and payable because of the occurrence of an event of default that remains applicable, the amount of money and/or U.S. Government Obligations on deposit with the trustee will be sufficient to pay amounts due on the original notes, at the time of their stated maturity, but may not be sufficient to pay amounts due on the notes at the time of acceleration resulting from such event of default. We will remain liable for such payments.

We and our affiliates use or will use some of the banking services of the trustee in the normal course of business.

The indenture and the notes will be governed by the laws of the Commonwealth of Pennsylvania.

"Adjusted Treasury Rate" means, with respect to any redemption date, the rate per year equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for the redemption date.

"Asset Sale" means any sale, lease, sale and leaseback transfer, conveyance or other disposition of any assets including by way of the issue by us or any of our Subsidiaries of equity interests in such Subsidiaries, except (1) in the ordinary course of business to the extent that such property is worn out or is no longer useful or necessary in connection with the operation of our business or sale inventory, (2) if, prior to such conveyance or disposition, each Rating Agency provides a ratings reaffirmation of the then existing rating of the exchange notes after giving effect to such Asset Sale or (3) the sale of the stock or assets of Sithe or any of its subsidiaries, as part of a sale and leaseback transaction or other financing involving the acquisition of the remaining 50.1% interest in Sithe.

"Business Day" means any day that is not a day on which banking institutions in New York City are authorized or required by law or regulation to close.

"Comparable Treasury Issue" means the United States Treasury security selected by the Quotation Agent as having a maturity comparable to the remaining term of the exchange notes that would be used, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the exchange notes.

"Indebtedness" of any person means (1) all indebtedness of the person for borrowed money, (2) all obligations of such person evidenced by bonds, debentures, notes or other similar instruments, (3) all obligations of such person to pay the deferred purchase price of property or services, (4) all indebtedness created or arising under any conditional sale or other title retention agreement with respect to property acquired by such person (even though the rights and remedies of the seller or lender under such agreement in the event of the default are limited to repossession or sale of such property), (5) all capital lease obligations of such person (excluding leases of property in the ordinary course of business), and (6) all Indebtedness of the type referred to in clauses (1) through (5) above secured by (or for which the holder of such Indebtedness has an existing right, contingent or otherwise, to be secured by) any lien or security interest on property.

"Rating Agencies" means Standard & Poor's Rating Services, Moody's Investors Services, Inc. and Fitch, Inc.

"Reference Treasury Dealer" means (1) each of Salomon Smith Barney Inc., Credit Suisse First Boston Corporation, Banc One Capital Markets, Inc. and their respective successors, unless any of them ceases to be a primary U.S. Government securities dealer in New York City (a "Primary Treasury Dealer"), in which case we will substitute another Primary Treasury Dealer; and (2) any other Primary Treasury Dealer selected by us.

"Reference Treasury Dealer Quotations" means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the trustee by that Reference Treasury Dealer at 5:00 p.m., New York City time, on the third Business Day preceding that redemption date.

"Subsidiary" means any corporation or other entity of which sufficient voting stock or other ownership or economic interests having ordinary voting power to elect a majority of the board of directors (or equivalent body) are at the time directly or indirectly held by us.

The indenture provides that, except during the continuance of an event of default thereunder, the trustee will perform only such duties as are specifically set forth in the indenture. During the existence of an event of default, the trustee will be required, in the exercise of its power, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the trustee will be under no obligation to exercise any of its rights or powers under the indenture at the request of any

holder of notes, unless the holder has offered to the trustee security and indemnity satisfactory to it against any loss, liability or expense. The trustee may resign at any time with respect to a series of securities by written notice in accordance with the indenture. In addition, the trustee may be removed upon the happening of certain events specified in the indenture. Following any resignation or removal of the trustee, our Board of Directors will promptly appoint a successor trustee with respect to the securities affected in accordance with the indenture.

The certificates representing the exchange notes will be in fully registered, global form without interest coupons.

Ownership of beneficial interests in a global note will be limited to persons who have accounts with DTC ("participants") or persons who hold interests through participants. Ownership of beneficial interests in a global note will be shown on, and the transfer of that ownership will be effected only through, records maintained by DTC or its nominee (with respect to interests of participants) and the records of participants (with respect to interests of persons other than participants).

So long as DTC or its nominee is the registered owner or holder of the global notes, DTC or such nominee, as the case may be, will be considered the sole record owner or holder of the exchange notes represented by such global notes for all purposes under the indenture. No beneficial owner of an interest in the global notes will be able to transfer that interest except in accordance with DTC's applicable procedures, in addition to those provided for under the indenture and, if applicable, Euroclear or Clearstream.

Payments of the principal of and interest on the global notes will be made to DTC or its nominee, as the case may be, as the registered owner thereof. None of us, the trustee, or any paying agent will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests in the global notes or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests.

We expect that DTC or its nominee, upon receipt of any payment of principal or interest in respect of the global notes, will credit participants, accounts with payments in amounts proportionate to their respective beneficial ownership interests in the principal amount of such global notes, as shown on the records of DTC or its nominee. We also expect that payments by participants to owners of beneficial interests in such global notes held through such participants will be governed by standing instructions and customary practices, as is now the case with securities held for the accounts of customers registered in the names of nominees for such customers.

DTC has advised us as follows: DTC is a limited purpose trust company organized under the laws of the State of New York, a "banking organization" within the meaning of the New York Banking Law, a member of the Federal Reserve System, a "clearing corporation" within the meaning of the New York Uniform Commercial Code and a "Clearing Agency" registered pursuant to the provisions of Section 17A of the Exchange Act. DTC was created to hold securities for its participants and facilitate the clearance and settlement of securities transactions between participants through electronic book-entry changes in accounts of its participants, thereby eliminating the need for physical movement of the exchange notes. Participants include securities brokers and dealers, banks, trust companies and clearing corporations and certain other organizations. Indirect access to the DTC system is available to others such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a participant, either directly or indirectly ("indirect participants").

Neither the trustee nor we will have any responsibility for the performance by DTC or its participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

If DTC is at any time unwilling or unable to continue as a depositary for the global notes and a successor depositary is not appointed within 90 days, we will issue definitive, certificated Senior Notes in exchange for the global notes.

Euroclear has advised us as follows: Euroclear was created in 1968 to hold securities for its participants and to clear and settle transactions between its participants through simultaneous electronic book-entry delivery against payment, thereby eliminating the need for physical movement of certificates and any risk from lack of simultaneous transfers of securities and cash. Euroclear provides various other services, including securities lending and borrowing, and interfaces with domestic markets in several countries. Euroclear is operated by Euroclear Bank S.A./N.V. (the "Euroclear Operator"), under contract with Euroclear Clearance Systems, S.C., a Belgian cooperative corporation (the "Cooperative"). All operations are conducted by the Euroclear Operator, and all Euroclear securities clearance accounts and Euroclear cash accounts are accounts with the Euroclear Operator, not the Cooperative. The Cooperative establishes policy for Euroclear on behalf of Euroclear participants. Euroclear participants include banks (including central banks), securities brokers and dealers and other professional financial intermediaries. Indirect access to Euroclear is also available to others that clear through or maintain a custodial relationship with a Euroclear participant, either directly or indirectly.

The Euroclear Operator was granted a banking license by the Belgian Banking and Finance Commission in 2000, authorizing it to carry out banking activities on a global basis. It took over operation of Euroclear from the Brussels, Belgium office of Morgan Guaranty Trust Company of New York on December 31, 2000.

Securities clearance accounts and cash accounts with the Euroclear Operator are governed by the Terms and Conditions Governing Use of Euroclear and the related Operating Procedures of the Euroclear System, and applicable Belgian law (collectively, the "Terms and Conditions"). The Terms and Conditions govern transfers of securities and cash within Euroclear, withdrawals of securities and cash from Euroclear, and receipts of payments with respect to securities in Euroclear. All securities in Euroclear are held on a fungible basis without attribution of specific certificates to specific securities clearance accounts. The Euroclear Operator acts under the Terms and Conditions only on behalf of Euroclear participants and has no record of or relationship with persons holding through Euroclear participants.

Distributions with respect to exchange notes held beneficially through Euroclear will be credited to the cash accounts of Euroclear participants in accordance with the Terms and Conditions, to the extent received by Euroclear.

Clearstream has advised us as follows: Clearstream is incorporated under the laws of The Grand Duchy of Luxembourg as a professional depositary. Clearstream holds securities for its participants and facilitates the clearance and settlement of securities transactions between its participants through electronic book-entry changes in accounts of its participants, thereby eliminating the need for physical movement of certificates. Clearstream provides to its participants, among other things, services for safekeeping, administration, clearance and settlement of internationally traded securities and securities lending and borrowing. Clearstream interfaces with domestic markets in several countries. As a professional depositary, Clearstream is subject to regulation by the Luxembourg Monetary Institute. Clearstream participants are financial institutions around the world, including securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. Indirect access to Clearstream is also available to others that clear through or maintain a custodial relationship with a Clearstream participant either directly or indirectly.

Distributions with respect to exchange notes held beneficially through Clearstream will be credited to cash accounts of Clearstream participants in accordance with its rules and procedures, to the extent received by Clearstream.

The following discussion is a summary of certain United States federal income tax consequences relevant to the acquisition, ownership and disposition of the exchange notes by the beneficial owners thereof ("Holders"). This discussion is limited to the tax consequences to the initial Holders of original notes who purchased the original notes at the issue price within the meaning of Section 1273 of the Internal Revenue Code of 1986, as amended (the "Code"), and does not address the tax consequences to subsequent purchasers of the original notes or the exchange notes. This summary does not purport to be a complete analysis of all of the potential United States federal income tax consequences relating to the purchase of the original notes or the exchange of original notes for exchange notes or the ownership and disposition of the Senior Notes, nor does this summary describe any federal estate or gift tax consequences.

There can be no assurance that the Internal Revenue Service ("IRS") will take a similar view of the tax consequences described herein. Furthermore, this discussion does not address all aspects of taxation that might be relevant to particular purchasers in light of their individual circumstances. For instance, this discussion does not address the alternative minimum tax provisions of the Code or special rules applicable to certain categories of purchasers (including dealers in securities or foreign currencies, insurance companies, regulated investment companies, financial institutions, tax-exempt entities, Holders whose functional currency is not the U.S. dollar and, except to the extent discussed below, Foreign Holders (as defined below)), or to purchasers who hold the notes as part of a hedge, straddle, conversion, constructive ownership or constructive sale transaction or other risk reduction transaction. This discussion is based on the provisions of the Code, the Treasury Regulations promulgated thereunder, and administrative and judicial interpretations thereof, all as in effect as of the date hereof and all of which are subject to change (possibly on a retroactive basis). This discussion below assumes that the original notes (and the exchange notes) have been (and will be) held as capital assets within the meaning of Code Section 1221.

You are urged to consult your tax advisor as to the specific tax consequences of an exchange of the original notes for exchange notes in light of such investor's particular tax situation, including the application and effect of the Code, as well as state, local and foreign income tax, estate and gift tax and other tax laws.

The following summary is a general description of certain United States federal income tax consequences applicable to a "United States Holder." For the purpose of this discussion, the term "United States Holder" means a Holder of an original note or an exchange note that is for United States federal income tax purposes: (1) a citizen or resident of the United States, (2) a corporation, partnership or other entity created or organized in or under the laws of the United States or of any political subdivision thereof, (3) an estate, the income of which is subject to United States federal income taxation regardless of its source, or (4) a trust, the administration of which is subject to the primary supervision of a court within the United States and which has one or more United States persons with authority to control all substantial decisions, or a trust that was in existence on August 20, 1996 and has elected to continue to be treated as a United States trust.

If a partnership (or an entity taxable as a partnership) holds the exchange notes, the United States federal income tax treatment of a partner generally will depend upon the status of the partner and the activities of the partnership. If you are a partner in a partnership (or an entity taxable as a partnership) holding exchange notes, you should consult your tax advisor.

The exchange of an original note for an exchange note pursuant to the registered exchange offer generally will not be taxable to the exchanging Holder for United States federal income tax purposes. As a result, an exchanging Holder:

This exchange offer is not expected to result in any United States federal income tax consequences to a nonexchanging Holder.

Interest paid on the exchange notes will generally be taxable to a United States Holder as ordinary interest income at the time the interest accrues or is received in accordance with such Holder's method of accounting for United States federal income tax purposes.

In general, upon the sale, redemption, retirement or other taxable disposition of an exchange note, a United States Holder will recognize capital gain or loss equal to the difference between the amount realized on such sale, redemption, retirement or other disposition (not including any amount attributable to accrued but unpaid interest that the United States Holder has not already included in gross income) and such Holder's adjusted tax basis in the note. Any amount attributable to accrued but unpaid interest that the United States Holder has not already included in gross income will be treated as a payment of interest. See "Payments of Interest" above. A United States Holder's adjusted tax basis in a note generally will equal the cost of the original note, reduced by any principal payments received by such Holder and increased by any accrued but unpaid interest the Holder has included in income.

A noncorporate United States Holder generally will be subject to a maximum tax rate of 20% on net capital gains realized by the Holder on the disposition of capital assets (including the notes) held for more than one year. Capital losses realized by a Holder from the disposition of capital assets (including the notes) during any taxable year are, with minor exceptions, deductible only to the extent of capital gains realized in that taxable year or subsequent taxable years.

The following summary is a general description of certain United States federal income tax consequences to a "Foreign Holder" (which, for the purpose of this discussion, means a Holder that is not a United States Holder). Special rules not discussed in this summary may apply to certain Foreign Holders, including a "controlled foreign corporation," a "passive foreign investment company," an "expatriate," or a "foreign personal holding company." The following summary is subject to the discussion below concerning backup withholding.

A Foreign Holder will not recognize gain or loss from the exchange of an original note for an exchange note regardless of whether such Holder is otherwise subject to United States federal income tax with respect to income derived from an original note or an exchange note under the rules described below.

Assuming that a Foreign Holder's income from an exchange note is not "effectively connected" with the conduct by such Holder of a trade or business in the United States, payments of interest on an exchange note to a Foreign Holder will not be subject to United States federal income tax or withholding tax, provided that:

Payments of interest on an exchange note that do not satisfy all of the foregoing requirements are generally subject to United States federal income tax withholding at a flat rate of 30% (or a lower applicable treaty rate, provided certain certification requirements are met).

Except to the extent otherwise provided under an applicable tax treaty, a Foreign Holder generally will be subject to United States federal income tax in the same manner as a United States Holder with respect to interest on an exchange note if such interest is effectively connected with the conduct of a United States trade or business by such Holder. Effectively connected interest income will not be subject to withholding tax if the Foreign Holder delivers an IRS Form W-8ECI to the paying agent. Effectively connected interest income received by a corporate Foreign Holder may also, under certain circumstances, be subject to an additional "branch profits tax" at a 30% rate (or lower treaty rate).

In general, a Foreign Holder will not be subject to United States federal income tax or withholding tax on the receipt of payments of principal on an exchange note or on any gain recognized on the sale, redemption, retirement or other taxable disposition of an exchange note, unless:

In order to obtain the exemption from U.S. federal income tax withholding described above, either (1) a Foreign Holder of an exchange note must provide a certificate containing its name and address, and certify, under penalties of perjury, to our paying agent that such Holder is a Foreign Holder, or (2) a securities clearing organization, bank or other financial institution that holds customer securities in the ordinary course of its trade or business (a "Financial Institution") that holds an exchange note on behalf of the Foreign Holder must (a) certify, under penalties of perjury, to our paying agent that the required certificate has been received from the Foreign Holder by it or by an intermediary Financial Institution and (b) furnish a copy of the certificates to our paying agent. A certificate described in this paragraph is effective only with respect to payments of interest made to the Foreign Holder after issuance of the certificate in the calendar year of its issuance and the two immediately succeeding calendar years. The foregoing certification may be provided by the Foreign Holder on IRS Form W-8BEN, W-8IMY or W-8EXP, as applicable.

Backup withholding tax (presently imposed at the rate of 30%) and certain information reporting requirements apply to certain payments of principal and interest or the proceeds of sale made to certain Holders of exchange notes.

In the case of a noncorporate United States Holder, information reporting requirements will apply to payments of principal or interest made by our paying agent on an exchange note. The payor will be required to impose backup withholding tax if:

Backup withholding and information reporting do not apply with respect to payments made to certain exempt recipients, including a corporation.

In the case of a Foreign Holder, backup withholding will not apply to payments of principal or interest made by our paying agent on an exchange note (absent actual knowledge that the Holder is actually a United States Holder) if the Foreign Holder has provided the required certification under penalties of perjury that it is not a United States Holder or has otherwise established an exemption from backup withholding. If the Foreign Holder provides the required certification, such Holder may nevertheless be subject to withholding of United States federal income tax as described above under "—Tax Consequences to Foreign Holders."

Federal withholding tax is not an additional tax. Rather, any amount withheld from a payment to a Holder is generally allowed as a credit against such Holder's United States federal income tax liability and may entitle the Holder to a refund provided that certain required information is provided to the IRS.

We are making the exchange offer in reliance on the position of the staff of the Division of Corporation Finance of the SEC as defined in certain interpretive letters issued to third parties in other transactions.

Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of such exchange notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for original notes where such original notes were acquired as a result of market-making activities or other trading activities. We have agreed that, starting on the Expiration Date and ending on the close of business one year after the Expiration Date, we will make this prospectus, as amended or supplemented, available to any broker-dealer that reasonably requests such document for use in connection with any such resale. Broker-dealers who acquired original notes directly from us may not rely on the staff's interpretations and must comply with the registration and prospectus delivery requirements of the Securities Act, including being named as a selling security holder, in order to resell the original notes or the exchange notes.

We will not receive any proceeds from any sale of exchange notes by broker-dealers. Exchange notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the exchange notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices.

Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer and/or the purchasers of any such exchange notes. Any broker-dealer that resells exchange notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such exchange notes may be deemed to be an "underwriter" within the meaning of the Securities Act and any profit on any such resale of exchange notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act.

The letter of transmittal states that by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.

For a period of one year after the exchange offer has been completed, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such document in the letter of transmittal.

We have agreed to pay all expenses incident to the exchange offer (including the expenses of one counsel for the holders of the original notes), other than commissions or concessions of any brokers or dealers, and will indemnify the holders of the exchange notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

By acceptance of this exchange offer, each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer agrees that, upon receipt of notice from us of the happening of any event which makes any statement in the prospectus untrue in any material respect or requires the making of any changes in the prospectus in order to make the statements therein not misleading (which notice we agree to deliver promptly to such broker-dealer), such broker-dealer will suspend use of the prospectus until we have amended or supplemented the prospectus to correct such misstatement or omission and have furnished copies of the amended or supplemental prospectus to such broker-dealer.

The validity of the exchange notes will be passed upon for us by Ballard Spahr Andrews & Ingersoll, LLP.

The financial statements of Exelon Generation Company, LLC as of December 31, 2001 and 2000 and for each of the three years ended December 31, 2001 included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers, LLP independent accountants, given on the authority of said firm as experts in auditing and accounting.

		Page(s)
Report of Independent Accountants		F-2
Consolidated Financial Statements:
	Statements of Income		F-3
	Statements of Cash Flows		F-4
	Balance Sheets		F-5
	Statements of Changes in Divisional/Member's Equity		F-6
	Statements of Other Comprehensive Income		F-7
	Notes to Consolidated Financial Statements		F-8 - 39

In our opinion, the accompanying consolidated balance sheets and related consolidated statements of income, cash flows, changes in divisional/member's equity and comprehensive income present fairly, in all material respects, the financial position of Exelon Generation Company, LLC and Subsidiary Companies (Exelon Generation) at December 31, 2001 and December 31, 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of Exelon Generation's management; our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 3 to the consolidated financial statements, Exelon Generation's parent company, Exelon Corporation, acquired Unicom Corporation on October 20, 2000 in a business combination accounted for under the purchase method of accounting. The results of the acquired generation-related business are included in the consolidated financial statements of Exelon Generation since the acquisition date.

As discussed in Note 1, Exelon Generation changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001.

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Millions)

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Millions)

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Dollars in Millions)

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

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN DIVISIONAL/MEMBER'S EQUITY

(Dollars in Millions)

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

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Millions)

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

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in Millions, unless otherwise noted)

Exelon Generation Company, LLC ("Exelon Generation") is a limited liability company engaged principally in the production and wholesale marketing of electricity in various regions of the United States. In 2001, the Company also began trading activities. Exelon Generation is wholly owned by Exelon Corporation (Exelon). In connection with the restructuring by Exelon to separate the regulated energy delivery business of its subsidiaries Commonwealth Edison Company (ComEd) and PECO Energy Company (PECO) from its unregulated businesses, including its generation business, Exelon Generation began operations as a separate indirect subsidiary of Exelon effective January 1, 2001. Exelon Generation has numerous wholly owned subsidiaries. These subsidiaries were primarily established to hold certain hydro electric and peaking unit facilities as well as the 49.9% interest in Sithe Energies, Inc. ("Sithe") and 20.99% investment in Keystone Fuels, LLC. In addition, Exelon Generation also has a finance company subsidiary, Exelon Generation Finance Company, LLC, which provides certain financing for Exelon Generation's other subsidiaries. Exelon Generation also owns a 50% investment in AmerGen Energy Company, LLC (AmerGen).

The consolidated financial statements include the accounts of all majority-owned subsidiaries of Exelon Generation after the elimination of intercompany accounts and transactions. Exelon Generation consolidates its proportionate interest in jointly owned electric utility plants. Exelon Generation accounts for its investments in 20% to 50% owned entities under the equity method of accounting.

The consolidated financial statements of Exelon Generation as of December 31, 2000 and for the years ended December 31, 2000 and 1999 present the financial position, results of operations and net cash flows of the generation-related business of Exelon prior to its corporate restructuring on January 1, 2001. Exelon Generation operated as a separate business subsequent to electric-industry restructuring in Pennsylvania effective January 1, 1999. Prior to that date, Exelon (and its predecessor, PECO Energy Company) operated as a fully integrated electric and gas utility, and revenues and expenses were not separately identified in the accounting records. The consolidated financial statements are not necessarily indicative of the financial position, results of operations or net cash flows that would have resulted had the generation-related business been a separate entity during the periods presented. For periods prior to the restructuring, references to Exelon Generation mean the generation-related business of Exelon Corporation.

Certain information in these consolidated financial statements relating to the results of operations and financial condition of Exelon Generation for periods prior to Exelon's restructuring was derived from the historical financial statements of Exelon. Various allocation methodologies were employed to separate the results of operations and financial condition of the generation-related portion of Exelon's business from the historical financial statements for the periods presented prior to the restructuring. Revenues include the generation component of revenue from Exelon's operations and any generation-related revenues, such as ancillary services and wholesale energy activity. Expenses including fuel and other energy-related costs, including purchased power, operations and maintenance and depreciation and amortization, as well as assets, such as property, plant and equipment, materials and supplies and fuel, were specifically identified for Exelon Generation's operations. Various allocations were used to

disaggregate other common expenses, assets and liabilities between Exelon Generation and Exelon's other businesses, primarily the regulated transmission and distribution operations.

Management believes that these allocation methodologies are reasonable; however, had Exelon Generation existed as a separate company prior to January 1, 2001, its results could have significantly differed from those presented herein. In addition, future results of operations, financial position and net cash flows could materially differ from the historical results presented.

Exelon Generation operates in one business comprising its generation and marketing of energy and energy-related products in the United States.

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of 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. Significant estimates have been made in the accounting for derivatives, nuclear decommissioning liabilities and estimated service lives for plant.

Operating revenues are generally recorded as service is rendered or energy is delivered to customers. At the end of each month, Exelon Generation accrues an estimate for unbilled energy provided to its customers. Premiums received and paid on option contracts and swap arrangements are amortized to revenue and expense over the life of the contracts. Certain of these contracts are considered derivative instruments and are recorded at fair value with subsequent changes in fair value recognized as revenues and expenses unless hedge accounting is applied.

Commodity derivatives used for trading purposes are accounted for using the mark-to-market method. Under this methodology, these derivatives are adjusted to fair value, and the unrealized gains and losses are recognized in current period income.

The cost of nuclear fuel is capitalized and charged to fuel expense using the units of production method. Estimated costs of nuclear fuel storage and disposal at operating plants are charged to expense as the related fuel is consumed.

Emission allowances are included in deferred debits and other assets and are carried at acquisition cost and charged to fuel expense as they are used in operations. Allowances held can be used from years 2002 to 2028.

Depreciation is provided over the estimated useful service lives of the property, plant and equipment on a straight-line basis. Nuclear power stations operate under licenses granted by the Nuclear Regulatory Commission ("NRC".) Operating licenses for Exelon Generation's operating plants are for 40 years. Exelon Generation has or intends to request 20 year extensions of these operating licenses. If not extended, nuclear plant service lives would be limited by the expiration of the licenses.

The average estimated useful service lives currently being applied to determine depreciation and decommissioning expense of property, plant and equipment by type of asset are as follows:

Exelon Generation's current estimate of the costs for decommissioning its ownership share of its nuclear generation stations is charged to operations over the expected service life of the plant. Exelon Generation's affiliates PECO and ComEd are currently recovering costs for the decommissioning of nuclear generating stations through regulated customer rates. Amounts collected for decommissioning by Exelon Generation's affiliates are remitted to Exelon Generation and are deposited in trust accounts and invested for the funding of future decommissioning costs. Exelon Generation accounts for the current period's cost of decommissioning related to generation plants previously owned by PECO by recording a charge to depreciation and decommissioning expense and a corresponding liability in accumulated depreciation concurrently with decommissioning collections.

For Exelon Generation's active nuclear generating stations previously owned by ComEd, annual decommissioning expense is based on an annual assessment of the difference between the current cost of decommissioning estimate and the decommissioning liability recorded in accumulated depreciation. The difference is amortized to depreciation and decommissioning expense on a straight-line basis over the remaining lives of the operating plants with the corresponding offset to accumulated depreciation. The current decommissioning cost estimate (adjusted annually to reflect inflation), for the former ComEd retired units recorded in deferred credits and other liabilities is accreted to depreciation and decommissioning expense. Exelon Generation believes that the amounts being recovered by ComEd and PECO from their customers through electric rates along with the earnings on the trust funds will be sufficient to fully fund its decommissioning obligations.

Exelon Generation capitalizes the costs during construction of debt funds used to finance its construction projects. Exelon Generation recorded capitalized interest of $17 million, $2 million and $6 million in 2001, 2000 and 1999, respectively.

As part of Exelon's consolidated group, Exelon Generation files a consolidated Federal income tax return with Exelon. Income taxes are allocated to each of Exelon subsidiaries within the consolidated group, including Exelon Generation, based on the separate return method.

Deferred Federal and state income taxes are provided on all temporary differences between book bases and tax bases of assets and liabilities. Investment tax credits previously used for income tax purposes have been deferred on Exelon Generation's consolidated balance sheet and are recognized in income over the life of the related property.

Exelon Generation considers all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents.

Marketable securities are classified as available-for-sale securities and are reported at fair value, with the unrealized gains and losses, net of tax, reported in other comprehensive income. The cost of these securities is determined on the basis of specific identification. At December 31, 2001 and 2000, Exelon Generation had no held-to-maturity or trading securities.

Unrealized gains and losses on marketable securities held in the nuclear decommissioning trust funds associated with the former PECO plants are reported in accumulated depreciation. Unrealized gains and losses on marketable securities held in the nuclear decommissioning trust funds associated with the former ComEd plants are reported in accumulated other comprehensive income.

Inventories, which consist primarily of fuel and materials and supplies, are valued at the lower of cost or market and are stated on the average cost method.

Property, plant and equipment is recorded at cost. Exelon Generation evaluates the carrying value of property, plant and equipment and other long-term assets based upon current and anticipated undiscounted cash flows, and recognizes an impairment when it is probable that such estimated cash flows will be less than the carrying value of the asset. Measurement of the amount of impairment, if any, is based upon the difference between carrying value and fair value. The cost of maintenance, repairs and minor replacements of property are charged to maintenance expense as incurred. The cost and accumulated depreciation of property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of the gain or loss on disposition.

Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to the member. Comprehensive income primarily relates to unrealized

gains or losses on securities held in nuclear decommissioning trust funds and unrealized gains and losses on cash flow hedge instruments.

Subsequent to January 1, 2001, Exelon Generation accounts for derivative financial instruments under SFAS No. 133 "Accounting for Derivatives and Hedging Activities" (SFAS No. 133). Under the provisions of SFAS No. 133, all derivatives are recognized on the balance sheet at their fair value unless they qualify for a normal purchases or normal sales exception. Derivative financial instruments are recorded as other assets and liabilities in the consolidated balance sheet and classified as current or non-current based on the maturity date. Changes in the fair value of the derivative financial instruments are recognized in earnings unless specific hedge accounting criteria are met. A derivative financial instrument can be designated as a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge), or a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge).

Changes in the fair value of a derivative that is highly effective as, and is designated and qualifies as, a fair value hedge, along with the gain or loss on the hedged asset or liability that is attributable to the hedged risk, are recorded in earnings. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as a cash flow hedge are recorded in other comprehensive income, until earnings are affected by the variability of cash flows being hedged.

Pursuant to Exelon's Risk Management Policy (RMP), Exelon Generation uses derivatives to manage the utilization of its available generating capability and provisions of wholesale energy to its affiliates. Exelon Generation also utilizes energy option contracts and energy financial swap arrangements to limit the market price risk associated with forward energy commodity contracts. Exelon Generation enters into certain energy related derivatives for trading or speculative purposes. Exelon Generation may also enter into derivatives to manage its exposure to fluctuation in interest rates related to its variable rate debt instruments, changes in interest rates related to planned future debt issuances prior to their actual issuance and changes in the fair value of outstanding debt which is planned for early retirement. As part of Exelon Generation's energy marketing business, Exelon Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While these contracts are considered derivative financial instruments under SFAS No. 133, the majority of these transactions have been designated as "normal purchases" and "normal sales" and are not subject to the provisions of SFAS No. 133. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and price is not tied to an unrelated underlying derivative. Under these contracts Exelon Generation recognizes gains or losses when the underlying physical transaction occurs. Revenues and expenses associated with market price risk management contracts are amortized over the terms of such contracts. The remainder of these contracts are generally considered cash flow hedges under SFAS No. 133.

Additionally, during 2001, as part of the creation of Exelon Generation's energy trading operation, Exelon Generation began to enter into contracts to buy and sell energy for trading purposes, subject to limits. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.

Prior to the adoption of SFAS No. 133, Exelon Generation applied hedge accounting only if the derivative reduced the risk of the underlying hedged item and was designated at the inception of the hedge, with respect to the hedged item. Exelon Generation recognized any gains or losses on these derivatives when the underlying physical transaction affected earnings.

Contracts entered into by Exelon Generation to limit market risk associated with forward energy commodity contracts are reflected in the financial statements at the lower or cost or market using the accrual method of accounting. Under these contracts Exelon Generation recognizes any gains or losses when the underlying physical transaction affects earnings. Revenues and expenses associated with market price risk management contracts were amortized over the terms of such contracts.

During 2001, the FASB issued SFAS No. 141, "Business Combinations" (SFAS No. 141), No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142), No. 143, "Asset Retirement Obligations" (SFAS No. 143) and No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144).

SFAS No. 141 requires that all business combinations be accounted for under the purchase method of accounting and establishes criteria for the separate recognition of intangible assets acquired in business combinations. SFAS No. 141 is effective for business combinations initiated after June 30, 2001. In addition, SFAS No. 141 requires that unamortized negative goodwill related to pre-July 1, 2001 purchase be allocated as a pro-rata reduction of the amounts that otherwise would have been assigned to the acquired assets. If any excess remains, that remaining excess is to be recognized as an extraordinary gain concurrent with the adoption of SFAS No. 142. Included on AmerGen's balance sheet is $43 million of negative goodwill net of accumulated amortization. Upon AmerGen's adoption of SFAS No. 141 in the first quarter of 2002. Exelon Generation expects to recognize its appropriate share of approximately $22 million, pre-tax, as a cumulative effect of a change in accounting principle.

SFAS No. 142 establishes new accounting and reporting standards for goodwill and intangible assets. Exelon Generation adopted SFAS No. 142 as of January 1, 2002. Under SFAS No. 142, goodwill will no longer be subject to amortization. After January 1, 2002, goodwill will be subject to an assessment for impairment using a fair value based test at least annually, or more frequently if events or circumstances indicate that goodwill might be impaired. An impairment loss would be reported as a reduction to goodwill and a charge to operating expense, except at the transition date, when the loss would be reflected as a cumulative effect of a change in accounting principle. As of December 31, 2001, Exelon Generation has no goodwill recorded on its consolidated balance sheet.

SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. Exelon Generation expects to adopt SFAS No. 143 on January 1, 2003. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract

or by legal construction under the doctrine of promissory estoppel. Adoption of SFAS No. 143 will change the accounting for the decommissioning of Exelon Generation's nuclear generating plants. Currently, Exelon Generation records the obligation for decommissioning ratably over the lives of the plants. The January 1, 2003 adoption of SFAS No. 143 will require a cumulative effect adjustment effective the date of adoption to adjust plant assets and decommissioning liabilities to the values they would have been had this standard been employed from the in-service dates of the plants. The effect of this cumulative adjustment will be to increase the decommissioning liability to reflect a full decommissioning obligation in current year dollars. Additionally, the SFAS No. 143 standard will require the accrual of an asset, to the extent allowable under the standard, related to the full amount of the decommissioning obligation, which will be amortized over the remaining lives of the plants. The net difference between the asset recognized and the liability recorded upon adoption of the standard will be charged to earnings and recognized as a cumulative effect, net of expected regulatory recovery. The decommissioning liability to be recorded represents an obligation for the future decommissioning of the plants, and as a result interest expense will be accrued on this liability until such time as the obligation is satisfied.

Exelon Generation is in the process of evaluating the impact of SFAS No. 143 on its financial statements, and cannot determine the ultimate impact of adoption at this time, however the cumulative effect could be material to Exelon's earnings. Additionally, although over the life of the plant the charges to earnings for the depreciation of the asset and the interest on the liability will be equal to the amounts currently recognized as decommissioning expense, the timing of those charges will change and in the near-term period subsequent to adoption, the depreciation of the asset and the interest on the liability could result in a significant increase in expense.

SFAS No. 144 establishes accounting and reporting standards for both the impairment and disposal of long-lived assets. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001 and provisions of SFAS No. 144 are generally applied prospectively. Exelon Generation is in the process of evaluating the impact of SFAS No. 144 on its financial.

On October 20, 2000 Exelon became the parent corporation for PECO and ComEd as a result of the completion of the transactions contemplated by the Agreement and Plan of Exchange and Merger, as amended (Merger Agreement) among PECO, Unicom Corporation and Exelon. The Merger was accounted for using the purchase method of accounting, with PECO as acquirer.

The fair value of the assets acquired and liabilities assumed in the merger associated with the generation-related business of ComEd are summarized below:

Exelon Generation has included the generation-related assets and liabilities of ComEd and the related results of operations in its consolidated financial statements beginning October 20, 2000. Exelon Generation's Statement of Changes in Member's Equity reflects the generation-related impacts of the Merger as a capital contribution from Exelon.

During January 2001, Exelon undertook a corporate restructuring to separate its generation and other competitive businesses from its regulated energy delivery businesses conducted by ComEd and PECO. As part of the restructuring, the generation-related operations, employees, assets, liabilities, and certain commitments of Exelon Corporation were transferred to Exelon Generation.

The assets and liabilities transferred to Exelon Generation as of January 1, 2001 were as follows:

Assets
Current assets		$	1,285
Property, plant and equipment			831
Nuclear fuel			896
Nuclear decommissioning trust funds			3,127
Investments			762
Deferred income taxes			337
Note receivable from affiliate			363
Other noncurrent assets			153

	Total assets transferred		7,754

Liabilities
Note payable to member			696
Current liabilities			1,146
Long-term debt			205
Decommissioning obligation for retired plants			1,301
Other noncurrent liabilities			1,970

	Total liabilities transferred		5,318

	Net assets transferred	$	2,436

On January 1, 2001, a non-cash distribution of $174 million was made in connection with the elimination of certain intercompany transactions.

In connection with the restructuring, ComEd and PECO also assigned their respective rights and obligations under various power purchase and fuel supply agreements to Exelon Generation. Additionally, Exelon Generation entered into power purchase agreements ("PPAs") to supply the capacity and energy requirements of ComEd and PECO.

On December 18, 2000, Exelon Generation acquired 49.9% of the outstanding common stock of Sithe for $696 million in cash and $8 million of acquisition costs. Sithe, headquartered in New York, is a leading independent power producer, with ownership interests in 27 facilities in North America. Sithe has net generation capacity of 3,371 MW, primarily in New York and Massachusetts, 2,651 MW under construction and 2,400 MW in advanced development.

Beginning December 18, 2002, Exelon Generation will have the right to purchase all (but not less than all) of the remaining outstanding shares of the Sithe common stock. The option expires on December 18, 2005. In addition, each of Sithe's other stockholder groups will have the right to require us to purchase all (but not less than all) of its shares during the same period in which Exelon Generation can exercise its option. At the end of that period, if no stockholder has exercised its option,

Exelon Generation will have a one-time option to purchase shares from the other stockholders to bring its holdings to 50.1% of the total outstanding shares. If Exelon Generation exercise its option or if all the stockholder groups exercise their put rights, the purchase price for 70% of the remaining 50.1% of the Sithe stock will be set at a fair market value plus a 10% premium in the case of a call or 10% discount in the case of a put, subject to a floor of $430 million and a ceiling of $650 million, and the remaining portion will be valued at fair market value, subject to a floor price of $141 million and a ceiling price of $330 million, plus, in each case, interest accrued from the beginning of the exercise period.

If Exelon Generation increases its ownership in Sithe to 50.1% or more, Sithe will become a consolidated subsidiary and Exelon Generation's financial results will include Sithe's financial results from the date of purchase. At December 31, 2001, Sithe had total assets of $4.2 billion and long-term debt of $2.3 billion, including $2.1 billion of non-recourse project debt, and excluding any non-recourse project debt associated with Sithe's equity investments. For the year ended December 31, 2001 Sithe had revenues of approximately $1 billion. In December 2001, Sithe entered into a new 18-month corporate credit facility for $500 million expiring in June 2003. As of December 31, 2001 Sithe had drawn approximately $176 million under this facility and extended approximately $161 million in letters of credit.

Exelon Generation's investment in Sithe as of December 31, 2001 and 2000 was $725 million and $704 million, respectively.

Exelon Generation and British Energy, Inc, a wholly owned subsidiary of British Energy, plc, each own a 50% equity interest in AmerGen Energy Company, LLC (AmerGen). Established in 1997, AmerGen was formed to pursue opportunities to acquire and operate nuclear generation facilities in the North America. Currently, AmerGen owns and operates three nuclear generation facilities: Clinton Power Station (Clinton) located in Illinois, Three Mile Island (TMI) Unit 1 located in Pennsylvania, and Oyster Creek, which was acquired in August 2000, located in New Jersey. Oyster Creek was acquired from GPU, Inc. (GPU) for $10 million. Under the terms of the purchase agreement, GPU agreed to fund outage cots of $89 million, including the cost of fuel, for a refueling outage that occurred in 2000. AmerGen is repaying these costs to GPU in equal annual installments through 2009. In addition, AmerGen assumed full responsibility for the ultimate decommissioning of Oyster Creek. At the closing of the sale, GPU provided funding for the decommissioning trust of $440 million. In conjunction with this acquisition, AmerGen has received a fully funded decommissioning trust fund which has been computed assuming the anticipated costs to appropriately decommission Oyster Creek discounted to net present value using the NRC's mandated rate of 2%. As part of each acquisition, AmerGen entered into a power sales agreement with the seller. The agreement with the seller for Clinton calls for Exelon Generation to sell 75% of the output back to Illinois Power for a term expiring at the end of 2005. The agreements with the seller of TMI and Oyster Creek are for all of the output expiring in 2001 and 2003, respectively.

AmerGen maintains a nuclear decommissioning trust fund for each of its plants in accordance with NRC regulations and believes that amounts in these trust funds, together with the investment earnings

thereon and additional contributions for Clinton from Illinois Power, will be sufficient to meet its decommissioning obligations.

Exelon Generation's investment in AmerGen as of December 31, 2001 and 2000 was $113 million and $44 million, respectively.

The table below presents summarized financial information for Sithe and AmerGen, Exelon Generation's unconsolidated equity affiliates:

	Year Ended December 31,
Income Statement Information	Year Ended December 31,
Income Statement Information	2001			2000		1999
Operating revenues	$	1,691		$	1,675	$	15
Operating income		297			546		4
Income before extraordinary items and cumulative effect of change in accounting principle		(8	)		254		4
Net income	$	(8	)	$	254	$	4

	Year Ended December 31,
Balance Sheet Information	Year Ended December 31,
Balance Sheet Information	2001			2000
Current assets	$	745		$	588
Noncurrent assets		5,126			3,930

Total assets	$	5,871		$	4,518

Current liabilities		591			1,072
Noncurrent liabilities		3,714			2,025
Members' capital		80			80
Undistributed earnings (deficit)		155			(1	)
Additional paid-in capital		735			735
Retained earnings		647			602
Accumulated other comprehensive income (loss)		(51	)		5

Total capitalization and liabilities	$	5,871		$	4,518

		December 31,
		2001		2000
Generation plant		$	4,344	$	4,142
Construction work-in-progress			610		380

Total property, plant and equipment			4,954		4,522
Less: accumulated depreciation (including decommissioning costs for active nuclear stations)			3,794		3,691

	Property, plant and equipment, net	$	1,160	$	831

Exelon Generation's ownership interest in jointly owned generation plant at December 31, 2001 and 2000 were as follows:

Exelon Generation's undivided ownership interests are financed with Exelon Generation funds and, when placed in service, all operations are accounted for as if such participating interests were wholly owned facilities.

On September 30, 1999, PECO reached an agreement to purchase an additional 7.51% ownership interest in Peach Bottom Atomic Power Station ("Peach Bottom") from Atlantic City Electric Company

("ACE") and Delmarva Power & Light Company ("DPL") for $18 million. With the purchase of the additional ownership interest in Peach Bottom, Exelon Generation received a transfer of $47 million representing ACE and DPL's decommissioning trust funds and the related liability for the station. As a result of the restructuring, the purchase agreement has been assigned to Exelon Generation. DPL's 3.755% interest was purchased in December 2000 by PECO and transferred to Exelon Generation as part of the restructuring. The purchase of ACE's 3.755% ownership interest was completed in October 2001.

Exelon Generation has an obligation to decommission its nuclear power plants. Exelon Generation's current estimate of its nuclear facilities' decommissioning cost for its owned nuclear plants is $7.2 billion in current year (2002) dollars. Nuclear decommissioning activity occurs primarily after the plants retirement and is currently estimated to begin in 2031. Exelon Generation's Zion Station permanently ceased power generation operations in 1998. The plant is currently being maintained in a secure and safe condition until final decommissioning, which is scheduled to begin in 2013. Decommissioning costs are currently recoverable through the regulated rates of ComEd and PECO. Exelon Generation collected $102 million in 2001 from ComEd and PECO. At December 31, 2001, the decommissioning liability recorded in accumulated depreciation and deferred credits and other liabilities was $2.7 billion and $1.3 billion, respectively. At December 31, 2000, the decommissioning liability recorded in Accumulated Depreciation and deferred credits and other liabilities was $2.6 billion and $1.3 billion, respectively. In order to fund future decommissioning costs, at December 31, 2001 and 2000, Exelon Generation held $3.2 billion and $3.1 billion, respectively, in trust accounts which are included as investments in Exelon Generation's Consolidated Balance Sheets at their fair market value. These trust funds are either qualified or non-qualified. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a "qualified fund." Contributions made into a qualified fund are tax deductible. Exelon Generation believes that the amounts being recovered from customers through regulated rates and earnings on nuclear decommissioning trust funds will be sufficient to fully fund its decommissioning obligations.

In connection with the transfer by ComEd of its nuclear generating stations to Exelon Generation, ComEd asked the Illinois Commerce Commission (ICC) to approve the continued recovery of decommissioning costs after the transfer. On December 20, 2000, the ICC issued an order finding that the ICC has the legal authority to permit ComEd to continue to recover decommissioning costs from customers for the six-year term of the power purchase agreements between ComEd and Exelon Generation. Under the ICC order, ComEd is permitted to recover $73 million per year from customers for decommissioning for the years 2001 through 2004. In 2005 and 2006, ComEd can recover up to $73 million annually, depending upon the portion of the output of the former ComEd nuclear stations that ComEd purchases from Exelon Generation. Under the ICC order, subsequent to 2006, there will be no further recoveries of decommissioning costs from customers. The ICC order also provides that any surplus funds after the nuclear stations are decommissioned must be refunded to customers. The ICC order is currently pending on appeal in the Illinois Appellate Court.

Exelon Generation recorded a receivable from ComEd of approximately $440 million representing ComEd's legal requirement to remit funds to Exelon Generation upon collection from customers, and

for collections from customers prior to the establishment of external decommissioning trust funds in 1989 to be remitted to Exelon Generation for deposit into the decommissioning trusts through 2006. Unrealized gains and losses on decommissioning trust funds (based on the market value of the assets on the Merger date, in accordance with purchase accounting) had previously been recorded in accumulated depreciation. As a result of the transfer of the ComEd nuclear plants to Exelon Generation and the ICC order limiting the regulated recoveries of decommissioning costs, net unrealized losses of $23 million (net of income taxes) at that date were reclassified to accumulated other comprehensive income. All subsequent realized gains and losses on these decommissioning trust funds' assets are based on the cost basis of the trust fund assets established on the Merger date and are reflected in Other Income and Deductions in Exelon Generation's Consolidated Statements of Income.

Nuclear decommissioning costs associated with the nuclear generating stations formerly owned by PECO continue to be recovered currently through rates charged by PECO to regulated customers these amounts are remitted to Exelon Generation as allowed by the Pennsylvania Public Utility Commission.

Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy (DOE) is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste (SNF). ComEd and PECO, as required by the NWPA, each signed a contract with the DOE (Standard Contract) to provide for disposal of SNF from their respective nuclear generating stations. In accordance with the NWPA and the Standard Contract, ComEd and PECO pay the DOE one mill ($.001) per kilowatt-hour of net nuclear generation for the cost of nuclear fuel long-term storage and disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contract required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 1998. The DOE, however, failed to meet that deadline and its performance is expected to be delayed significantly. The DOE's current estimate for opening an SNF facility is 2010. This extended delay in SNF acceptance by the DOE has led to Exelon Generation's use of dry storage at its Dresden and Peach Bottom Units and its consideration of dry storage at other units.

In July 2000, PECO entered into an agreement with the DOE relating to Peach Bottom nuclear generating unit to address the DOE's failure to begin removal of SNF in January 1998 as required by the Standard Contract. Under that agreement, the DOE agreed to provide credits against future contributions to the Nuclear Waste Fund over the next ten years to compensate for SNF storage costs incurred as a result of the DOE's breach of the contract. The agreement also provides that the DOE will take title to the SNF upon request and the interim storage facility at Peach Bottom provided certain conditions are met.

In November 2000, eight utilities with nuclear power plants filed a Joint Petition for Review against the DOE with the United States Court of Appeals for the Eleventh Circuit seeking to invalidate that portion of the agreement providing for credits against nuclear waste fund payments on the ground that such provision is a violation of the NWPA. PECO intervened as a defendant in that case, which is ongoing. In April, 2001, an individual filed suit against the DOE with the United States District Court for the Middle District of Pennsylvania seeking to invalidate the agreement on the grounds that the DOE has violated the National Environmental Policy Act and the Administrative Procedure Act. PECO

intervened as a defendant and moved to dismiss the complaint. The Court has not yet ruled on the motion to dismiss.

The Standard Contract with the DOE also requires that PECO and ComEd pay the DOE a one-time fee applicable to nuclear generation through April 6, 1983. PECO's fee has been paid. Pursuant to the Standard Contract, ComEd elected to defer payment of the one-time fee of $277 million, with interest accruing to the date of payment, just prior to the first delivery of SNF to the DOE. As of December 31, 2001, the liability for the one-time fee with interest was $843 million.

The liabilities for spent nuclear fuel disposal costs, including the one-time fee, were transferred to Exelon Generation as part of the corporate restructuring.

Long-term debt maturities in the period 2002 through 2006 and thereafter are as follows:

In May 2001, Exelon Generation entered into a forward-starting interest rate swap, with an aggregate notional amount of $700 million, to hedge the interest rate risk related to the anticipated issuance of debt. On June 11, 2001, Exelon Generation issued $700 million of senior unsecured notes with a maturity date of June 15, 2011 and an interest rate of 6.95% and closed the forward-starting interest rate swap. The aggregate loss on the settlement of the swap of $2 million, net of related income taxes, was classified in Accumulated Other Comprehensive Income and is being amortized to interest expense over the life of the debt.

Also during 2001, Exelon Generation issued $121 million of Pollution Control Revenue Refunding Bonds at an average variable commercial paper interest rate of 2.685% with maturities of 20 to 33 years. The proceeds from these offerings were used to refund tax-exempt debt previously issued by PECO. The transaction was accounted for as a distribution to the member.

Exelon Generation, together with Exelon, ComEd and PECO, entered into a $1.5 billion 364 day unsecured revolving credit facility on December 12, 2001 with a group of banks. As of December 31, 2001, Exelon Generation did not meet the requirements to borrow under this facility.

Income tax expense (benefit) is comprised of the following components for the years ended December 31:

			2001			2000			1999
Included in operations:
	Federal:
		Current	$	253		$	177		$	92
		Deferred		15			(38	)		18
		Investment tax credit, net		(8	)		(13	)		(12	)
	State:
		Current		51			43			22
		Deferred		16			(9	)		5

			$	327		$	160		$	125

Included in cumulative effect of a change in accounting principle:
Federal—deferred			$	6		$	—		$	—
State—deferred				1			—			—

			$	7			—			—

The effective income tax rate differed from the Federal statutory rate for the years ended December 31 principally due to the following:

		2001		2000		1999
Income taxes on above at Federal statutory rate of 35%		35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	5.2	%	5.0	%	5.2	%
	Nuclear decommissioning trust income	(0.6	)%	0.0	%	—
	Amortization of investment tax credit	(0.6	)%	(1.9	)%	(2.1	)%
	Other, net	—		—		(0.1	)%

Effective income tax rate		39.0	%	38.1	%	38.0	%

The tax effect of temporary differences giving rise to Exelon Generation's deferred tax assets and liabilities as of December 31, 2001 and 2000 are presented below:

Prior to 2001, the offsetting deferred tax assets and liabilities resulting from decommissioning and decontamination assets and obligations, accounted for as regulatory assets and liabilities, were recorded within the plant basis difference caption above. As a result of the corporate restructuring, on January 1, 2001, the decommissioning and decontamination obligations were transferred to Exelon Generation. The deferred tax asset related to the decommissioning and decontamination obligation is no longer recorded in the plant basis difference caption with the regulatory assets and liabilities.

Included in accrued expenses on Exelon Generation's consolidated balance sheets at December 31, 2001 and 2000 was approximately $245 and $334 million current taxes payable due to the member.

The Internal Revenue Service and certain state tax authorities are currently auditing certain tax returns of Exelon's predecessor entities, Unicom and PECO. The current audits are not expected to have an adverse effect on financial condition or results of operations of Exelon Generation.

Exelon Generation has adopted defined benefit pension plans and postretirement welfare plans sponsored by Exelon. Essentially all Exelon Generation employees are eligible to participate in these plans. Essentially all Exelon Generation management employees, and electing union employees, hired on or after January 1, 2001 are eligible to participate in the newly established Exelon cash balance pension plan. Management employees who were active participants in the pension plans on December 31, 2000 and remain employed on January 1, 2002, will have the opportunity to continue to participate in the pension plans or to transfer to the cash balance plan. Benefits under these pension plans generally reflect each employee's compensation, years of service, and age at retirement. Funding is based upon actuarially determined contributions that take into account the amount deductible for

income tax purposes and the minimum contribution required under the Employee Retirement Income Security Act of 1974, as amended. The following tables provide a reconciliation of benefit obligations, plan assets, and funded status of Exelon Generation's proportionate interest in the Exelon plans.

	Pension Benefits						Other Postretirement Benefits
	2001			2000			2001			2000
Change in Benefit Obligation:
Net benefit obligation at beginning of year	$	2,757		$	893		$	1,144		$	351
Service cost		37			17			17			11
Interest cost		166			91			70			33
Plan participants' contributions		—			—			2			—
Plan amendments		19			—			(105	)		—
Actuarial (gain)loss		102			102			72			77
Acquisitions		—			1,689			—			670
Curtailments/Settlements		(16	)		(32	)		—			2
Special accounting costs		13			90			2			25
Gross benefits paid		(202	)		(93	)		(70	)		(25	)

Net benefit obligation at end of year	$	2,876		$	2,757		$	1,132		$	1,144

Change in Plan Assets:
Fair value of plan assets at beginning of year	$	2,908		$	1,296		$	635		$	108
Actual return on plan assets		(111	)		82			(7	)		(6	)
Employer contributions		14			1			40			40
Plan participants' contributions		—			—			2			1
Acquisitions		—			1,622			—			517
Gross benefits paid		(202	)		(93	)		(70	)		(25	)

Fair value of plan assets at end of year	$	2,609		$	2,908		$	600		$	635

Funded status at end of year	$	(267	)	$	151		$	(532	)	$	(509	)
Miscellaneous adjustment		—			—			—			3
Unrecognized net actuarial (gain)loss		110			(347	)		207			75
Unrecognized prior service cost		46			33			(105	)		—
Unrecognized net transition obligation (asset)		(7	)		(9	)		46			54

Net amount recognized at end of year	$	(118	)	$	(172	)	$	(384	)	$	(377	)

Prior service cost is amortized on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans.

Special accounting costs in 2000 of $90 million include $42 million for separation benefits and $48 million for plan enhancements. Exelon Generation provides certain health care and life insurance benefits for retired employees through plans sponsored by Exelon. In 2001, Exelon amended the postretirement medical benefit plan to change the eligibility requirement of the plan to cover only employees who retire with 10 years of service after age 45 rather than with 10 years of service and having attained the age of 55. Welfare benefits for active employees are provided by several insurance policies or self-funded plans whose premiums or contributions are based upon the benefits paid during the year.

Exelon Generation has savings plans for the majority of its employees. The plans allow employees to contribute a portion of their pretax income in accordance with specified guidelines. Exelon Generation matches a percentage of the employee contribution up to certain limits. The cost of Exelon Generation's matching contribution to the savings plans totaled $15 million in 2001.

Exelon Generation participates in a 401(k) Savings Plan for Employees sponsored by Exelon. The plan allows employees to contribute a portion of their pretax income in accordance with specified guidelines. Exelon Generation matches a percentage of employee contributions to the plan up to certain limits. Exelon Generation expensed matching contributions to the plan totaling $23 million for 2001, $7 million for 2000 and $3 million for 1999.

Capital expenditures for production include expenditures to increase capacity of existing plants.

Exelon Generation has committed to provide AmerGen with capital contributions equivalent to 50% of the purchase price of any acquisitions AmerGen makes in 2002 and Exelon Generation and British Energy have each agreed to provide up to $100 million to AmerGen at any time for operating expenses.

In December 2001, Exelon Generation agreed to purchase two generation plants located in the Dallas-Fort Worth metropolitan area from TXU Corp. (TXU) to expand its presence in the Texas region. The $443 million purchase (not included in above table) of the two natural-gas and oil-fired plants, to be funded through available cash and commercial paper proceeds, will add approximately 2,300 megawatts (MW) capacity. The transaction includes a power purchase agreement for TXU to purchase power during the months of May through September from 2002 through 2006. During the periods covered by the power purchase agreement, TXU will make fixed capacity payments and will provide fuel to Exelon Generation in return for exclusive rights to the energy and capacity of the generation plants. The closing of the acquisition is contingent upon receipt of the necessary regulatory approvals and is anticipated to occur in the second quarter of 2002.

The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. The current limit is $9.5 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. Exelon Generation carries the maximum available commercial insurance of $200 million and the remaining $9.3 billion is provided through mandatory participation in a financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed up to $89 million per reactor per incident, payable at no more than $10 million per reactor per incident per year. This assessment is subject to inflation and state premium taxes. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims. Price-Anderson is scheduled to expire on August 1, 2002. Although replacement legislation has been proposed from time to time, Exelon Generation is unable to predict whether replacement legislation will be enacted.

Exelon Generation carries property damage, decontamination and premature decommissioning insurance for each station loss resulting from damage to its nuclear plants. In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Exelon Generation is required by the Nuclear Regulatory Commission ("NRC") to maintain, to provide for decommissioning the facility. Exelon Generation is unable to predict the timing of the availability of insurance proceeds to Exelon Generation and the amount of such proceeds which would be available. Under the terms of the various insurance agreements, Exelon Generation could be assessed up to $121 million for losses incurred at any plant insured by the insurance companies. In the event that one or more acts of terrorism cause accidental property damage within a twelve month period from the first accidental property damage under one or more policies for all insureds, the maximum recovery for all losses by all insureds will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity, and any other source, applicable to such losses.

Additionally, Exelon Generation is a member of an industry mutual insurance company that provides replacement power cost insurance in the event of a major accidental outage at a nuclear station. The premium for this coverage is subject to assessment for adverse loss experience. Exelon Generation's maximum share of any assessment is $46 million per year.

In addition, Exelon Generation participates in the American Nuclear Insurers Master Worker Program, which provides coverage for worker tort claims filed for bodily injury caused by a nuclear energy accident. This program was modified, effective January 1, 1998, to provide coverage to all workers whose "nuclear-related employment" began on or after the commencement date of reactor operations. Exelon Generation will not be liable for a retrospective assessment under this new policy. However, in the event losses incurred under the small number of policies in the old program exceed accumulated reserves, a maximum retroactive assessment of up to $50 million could apply.

Exelon Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon Generation's financial condition and results of operations.

Exelon Generation's wholesale operations include the physical delivery and marketing of power obtained through its generation capacity, and long, intermediate and short-term contracts. Exelon Generation maintains a net positive supply of energy and capacity, through ownership of generation assets and power purchase and lease agreements, to protect it from the potential operational failure of one of its owned or contracted power generation units. Exelon Generation has also contracted for access to additional generation through bilateral long-term power purchase agreements. These agreements are firm commitments related to power generation of specific generation plants and/or are dispatchable in nature—similar to asset ownership. Exelon Generation enters into power purchase agreements with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to its customers. Exelon Generation has also purchased firm transmission rights to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs. The intent and business objective for the use of its capital assets and contracts are to provide Exelon Generation with physical power supply to enable it to deliver energy to meet customer needs. Exelon primarily uses financial contracts in its wholesale marketing activities for hedging purposes. Exelon also uses financial contracts to manage the risk surrounding trading for profit activities.

Exelon Generation has entered into bilateral long-term contractual obligations for sales of energy to ComEd, PECO and other load-serving entities, including electric utilities, municipalities, electric cooperatives, and retail load aggregators. Exelon Generation also enters into contractual obligations to deliver energy to wholesale market participants who primarily focus on the resale of energy products for delivery. Exelon Generation provides delivery of its energy to these customers through rights for firm transmission. In addition, Exelon Generation has entered into long-term power purchase agreements with independent power producers ("IPP") under which Exelon Generation makes fixed capacity payments to the IPP in return for exclusive rights to the energy and capacity of the generation units for a fixed period.

At December 31, 2001, Exelon Generation's long-term commitments, relating to the purchase and sale of energy, capacity and transmission rights from affiliated and unaffiliated entities are as expressed in the following tables:

Included in Exelon Generation's long-term commitments are power purchase arrangements (PPAs) with Midwest Generation, LLC Midwest Generation for the purchase of capacity from its coal fired stations, in declining amounts through 2004. Contracted capacity and capacity available through the exercise of an annual option are as follows (in megawatts):

The agreements with Midwest Generationa also provide for the option to purchase 2,698 megawatts of oil and gas-fired capacity, and 944 megawatts of peaking capacity, subject to reduction.

Exelon Generation has entered into PPAs with AmerGen, under which it will purchase all the energy from Unit No. 1 at TMI after December 31, 2001 through December 31, 2014. Under a 1999 PPA, Generation will purchase from AmerGen all of the residual energy from Clinton through December 31, 2002. Currently, the residual output approximates 25% of the total output of the Clinton facility.

Exelon Generation's operations have in the past and may in the future require substantial capital expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, Exelon Generation is generally liable for the costs of remediating environmental contamination of property now owned and of property contaminated by hazardous substances generated by Exelon Generation.

As of December 31, 2001, Exelon Generation had accrued $14 million for environmental investigation and remediation costs. Exelon Generation cannot reasonably estimate whether it will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by Exelon Generation, environmental agencies or others, or whether such costs will be recoverable from third parties.

Minimum future operating lease payments, including lease payments for real estate, rail cars and office equipment, as of December 31, 2001 were:

Rental expense under operating leases totaled $29 million $19 million and $18 million for the year ended December 31, 2001, 2000 and 1999, respectively.

Cajun Electric Power Cooperative, Inc. On May 27, 1998, the United States Department of Justice, on behalf of the Rural Utilities Service and the Chapter 11 Trustee for the Cajun Electric Power Cooperative, Inc. ("Cajun"), filed an action claiming breach of contract against PECO in the United States District Court for the Middle District of Louisiana arising out of PECO's termination of the contract to purchase Cajun's interest in the River Bend nuclear power plant. Effective with the corporate restructuring, Exelon Generation has agreed to assume any liability and obligation arising from this litigation. During 2001, the parties reached a settlement of the dispute, and Exelon Generation made a payment of $14 million to Cajun.

Cotter Corporation. During 1989 and 1991, actions were brought in federal and state courts in Colorado against ComEd and its subsidiary, Cotter Corporation (Cotter), seeking unspecified damages and injunctive relief based on allegations that Cotter permitted radioactive and other hazardous material to be released from its mill into areas owned or occupied by the plaintiffs, resulting in property damage and potential adverse health effects. In 1994, a federal jury returned nominal dollar verdicts against Cotter on eight plaintiffs' claims in the 1989 cases, which verdicts were upheld on appeal. The remaining claims in the 1989 actions were settled or dismissed. In 1998, a jury verdict was rendered against Cotter in favor of 14 of the plaintiffs in the 1991 cases, totaling approximately $6 million in compensatory and punitive damages, interest and medical monitoring. On appeal, the Tenth Circuit Court of Appeals reversed the jury verdict, and remanded the case for new trial. These plaintiffs' cases were consolidated with the remaining 26 plaintiffs' cases, which had not been tried. The consolidated trial was completed on June 28, 2001. The jury returned a verdict against Cotter and

awarded $16.3 million in various damages. On November 20, 2001, the District Court entered an amended final judgment which included an award of both pre-judgment and post-judgment interests, costs, and medical monitoring expenses which total $43.3 million. This matter is being appealed by Cotter in the Tenth Circuit Court of Appeals. Cotter will vigorously contest the award.

The United States Environmental Protection Agency (EPA) has advised Cotter that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached barium sulfate at the site. Cotter, along with three other companies identified by the EPA as potentially responsible parties (PRPs), is reviewing a draft feasibility study that recommends capping the site. The PRPs are also engaged in discussions with the State of Missouri and the EPA. The estimated costs of remediation for the site are $10 to $15 million. Once a final feasibility study is complete and a remedy selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. Until an agreement is reached, Exelon Generation cannot predict its share of the costs.

In connection with the corporate restructuring, the responsibility to indemnify Cotter for any liability related to these matters was transferred to Exelon Generation. Management believes it has established an adequate contingent liability in connection with these proceedings.

Godley Park District Litigation. On April 18, 2001, the Godley Park District filed suit in Will County Circuit Court against ComEd and Exelon alleging that oil spills at Braidwood Station have contaminated the Park District's water supply. The complaint sought actual damages, punitive damages of $100 million and statutory penalties. The court dismissed all counts seeking punitive damages and statutory penalties, and the plaintiff has filed an amended complaint before the court. Exelon Generation is contesting the liability and damages sought by plaintiff.

Pennsylvania Real Estate Tax Appeals. Exelon Generation is involved in tax appeals regarding two of its nuclear facilities, Limerick (Montgomery County) and Peach Bottom (York County) and one of its fossil facilities, Eddystone (Delaware County), Exelon is also involved in the appeal for TMI (Dauphin County) through AmerGen. Exelon Generation does not believe the outcome of these matters will have a material adverse effect on Exelon Generation's results of operations or financial condition.

Enron. Exelon Generation is an unsecured creditor in Enron Corp.'s (Enron) bankruptcy proceeding. Exelon Generation's claim for power and other products sold to Enron in November and early December 2001 is $8.5 million. Enron may assert that Exelon Generation should not have closed

out and terminated all of its forward contracts with Enron. If Enron is successful in this argument, Exelon Generation's exposure could be greater than $8.5 million. Exelon Generation may also be subject to exposure due to the credit policies of ISO-operated spot markets that allocate defaults of market participants to non-defaulting participants. Exelon Generation has established an allowance for uncollectibles in anticipation of resolution of these matters.

General. Exelon Generation is involved in various other litigation matters. The ultimate outcome of such matters, while uncertain, is not expected to have a material adverse effect on Exelon Generation's financial condition or results of operations.

The carrying amounts and fair values of Exelon Generation's financial assets and liabilities as of December 31 were as follows:

As of December 31, 2001 and 2000, Exelon Generation's carrying amounts of cash and cash equivalents and accounts receivable are representative of fair value because of the short-term nature of these instruments. Fair values of the trust accounts for decommissioning nuclear plants and long-term debt are estimated based on quoted market prices for the same or similar issues. The fair value of Exelon Generation's and power purchase and sale contracts is determined using quoted exchange prices, external dealer prices, or internal valuation models which utilize assumptions of future energy prices and available market pricing curves. The fair value of Exelon Generation's energy derivatives is reported in the balance sheet as current or non-current assets or liabilities depending on the time until settlement of the transaction. At December 31, 2001, the following amounts were reported in Exelon Generation's consolidated balance sheet for the fair value of energy derivatives: accounts receivable of $109 million; other non-current assets of $62; accounts payable of $71; and non-current liabilities of $8.

Financial instruments that potentially subject Exelon Generation to concentrations of credit risk consist principally of cash equivalents, customer accounts receivable and energy derivatives. Exelon Generation places its cash equivalents with high-credit quality financial institutions. Generally, such investments are in excess of the Federal Deposit Insurance Corporation limits.

Exelon Generation utilizes derivatives to manage the utilization of its available generating capacity and provision of wholesale energy to its affiliates. Exelon Generation also utilizes energy option contracts and energy financial swap arrangements to limit the market price risk associated with forward energy commodity contracts. Additionally, Exelon Generation enters into certain energy-related derivatives for trading or speculative purposes. Exelon Generation would be exposed to credit-related losses in the event of non-performance by the counterparties that issued the derivative instruments. The credit exposure of derivatives contracts is represented by the fair value of contracts at the reporting date. The majority of power purchase and sale contracts are documented under master netting agreements.

On January 1, 2001, Exelon Generation recognized a non-cash gain of $12 million, net of income taxes, in earnings and deferred a non-cash gain of $5 million, net of income taxes, in accumulated other comprehensive income, a component of shareholders' equity, to reflect the initial adoption of SFAS No. 133, as amended. SFAS No. 133 must be applied to all derivative instruments and requires that such instruments be recorded in the balance sheet either as an asset or a liability measured at their fair value through earnings, with special accounting permitted for certain qualifying hedges.

During 2001, Exelon Generation recognized net gains of $16 million ($10 million, net of income taxes) relating to mark-to-market (MTM) adjustments of certain non-trading power purchase and sale contracts pursuant to SFAS No. 133. MTM adjustments on power purchase contracts are reported in fuel and purchased power and MTM adjustments on power sale contracts are reported as Operating Revenues in the Consolidated Statements of Income. During 2001, Exelon Generation recognized net gains aggregating $14 million ($10 million, net of income taxes) on derivative instruments entered into for trading purposes. Exelon Generation commenced financial trading in the second quarter of 2001. Gains and losses associated with financial trading are reported as either operating revenue or fuel and purchased power expense in the Consolidated Statements of Income. During 2001, no amounts were reclassified from accumulated other comprehensive income into earnings as a result of forecasted energy commodity transactions no longer being probable.

As of December 31, 2001, approximately $50 million of deferred net gains on derivative instruments accumulated in other comprehensive income are expected to be reclassified to earnings during the next twelve months. Amounts in accumulated other comprehensive income related to interest rate cash flows are reclassified into earnings when the forecasted interest payment occurs. Amounts in accumulated other comprehensive income related to energy commodity cash flows are reclassified into earnings when the forecasted purchase or sale of the energy commodity occurs. The majority of Exelon Generation's cash flow hedges are expected to settle within the next 3 years.

Exelon Generation classifies investments in the trust accounts for decommissioning nuclear plants as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized costs bases for the securities held in these trust accounts.

Net unrealized losses of $84 million and net unrealized gains of $5 million, respectively, were recognized in Accumulated Depreciation and Other Comprehensive Income in Exelon Generation's Consolidated Balance Sheets at December 31, 2001 and 2000, respectively.

Net realized gains of $14 million and net realized losses of $37 million were recognized in Accumulated Depreciation in Exelon Generation's Consolidated Balance Sheets at December 31, 2001 and 2000, respectively, and $127 million of net realized losses was recognized in Other Income and Deductions in Exelon Generation's Consolidated Income Statements for 2001. The available-for-sale securities held at December 31, 2001 have an average maturity of eight to ten years.

The information shown below, in the opinion of management, includes all adjustments, consisting only of normal or recurring accruals, necessary to a fair presentation of such amounts. Due to the seasonal nature of the generation business, quarterly amounts vary significantly during the year.

At December 31, 2000, Exelon Generation had a $696 million demand note payable, that was due no later than December 16, 2001, with Exelon related to the acquisition of Sithe, which was reflected in current liabilities in Exelon Generation's Consolidated Balance Sheet. Interest expense on the note payable was $23 million and $2 million for the years ended December 31, 2001 and 2000. The loan was repaid in full in June 2001.

At December 31, 2001, Exelon Generation had a long-term receivable of $291 million from ComEd resulting from the restructuring which is included in deferred debits and other assets, on Exelon Generation's consolidated balance sheet. This receivable represents ComEd's legal requirement to remit the recovery of decommissioning costs upon collection from the customers.

Effective January 1, 2001, upon the corporate restructuring, Exelon Generation receives a variety of corporate support services from the Business Services Company ("BSC"), a subsidiary of Exelon, including executive management, legal, human resources, financial and information technology services. Such services are provided at cost including applicable overheads. Costs charged to Exelon Generation by BSC for the year ended December 31, 2001 were $78 million.

In connection with the restructuring transaction, ComEd and PECO entered into PPAs with Exelon Generation. Under the PPA between Exelon Generation and ComEd, Exelon Generation supplies all of ComEd's load requirements through 2004. Prices for energy vary depending upon the time of day and month of delivery, as specified in the PPA. During 2005 and 2006, ComEd will purchase energy and capacity from Exelon Generation, up to the available capacity of the nuclear

generation plants formerly owned by ComEd and transferred to Exelon Generation. Under the terms of the PPA with ComEd, Exelon Generation is responsible for obtaining the required transmission for its supply. The PPA with ComEd also specifies that prior to 2005, ComEd and Exelon Generation will jointly determine and agree on a market-based price for energy delivered under the PPA for 2005 and 2006. In the event that the parties cannot agree to market-based prices for 2005 and 2006 prior to July 1, 2004, ComEd has the option of terminating its PPA effective December 31, 2004.

Exelon Generation has also entered into a PPA with PECO whereby Exelon Generation will supply all of PECO's load requirements through 2010. Prices for energy are equivalent to the net proceeds from sales of unbundled generation to PECO's provider of last resort customers at rates PECO is allowed to charge customers who do not choose an alternate generation supplier. Under the terms of PPA, PECO is responsible for obtaining the required transmission for its supply.

Intercompany power purchases pursuant to the PPAs for the year ended December 31, 2001 for ComEd and PECO were $2.6 billion and $1.2 billion, respectively. Prior to the restructuring, Exelon Generation recorded revenues of $871 million and $798 million related to sales of energy to PECO for 2000 and 1999, respectively. During 2000, Exelon Generation recorded revenue of $403 million related to sales of energy to ComEd.

Exelon Generation has entered into a PPA dated November 22, 1999 with AmerGen. Under this PPA, Exelon Generation has agreed to purchase from AmerGen all of the residual energy from the Clinton Power Station through December 31, 2002. Currently, the residual output approximates 25% of the total output of the Clinton Power Station. For the years ended December 31, 2001 and 2000, the amount of purchased power recorded in Consolidated Statements of Income is $57 million and $52 million, respectively. As of December 31, 2001 and 2000, Exelon Generation had a payable of $3.1 million and $2.9 million, respectively, resulting from this PPA.

In addition, under a service agreement dated March 1, 1999, Exelon Generation provides AmerGen with certain operation and support services to the nuclear facilities owned by AmerGen. This service agreement has an indefinite term and may be terminated by Exelon Generation or by AmerGen on 90 days' notice. Exelon Generation is compensated for these services in an amount agreed to in the work order but not less than the higher of the fully allocated costs for performing the services or the market price. For the years ended December 31, 2001, 2000 and 1999, the amount charged to AmerGen for these services was $80 million, $32 million and $1 million respectively. As of December 31, 2001 and 2000, Exelon Generation had a receivable of $47 million and $20 million respectively resulting from these services.

In February 2002, Exelon Generation entered into an agreement to loan AmerGen up to $75 million at an interest rate of one-month LIBOR plus 2.25%. As of March 1, 2002, AmerGen had borrowed $30 million under this agreement. The loan is due November 1, 2002.

In August 2001, Exelon Generation recorded a $150 million note receivable from Sithe. Sithe used the proceeds from the note to repay its subordinated debt. The note has a maturity date of August 20,

2004 and an interest rate of the Eurodollar rate, plus 2.25%. Sithe repaid this note in December 2001. For the year ended December 31, 2001, Exelon recorded $2.7 million of interest income on the note.

Beginning December 18, 2002, we will have the right to purchase all (but not less than all) of the remaining outstanding shares of the Sithe common stock. The option expires on December 18, 2005. In addition, each of Sithe's other stockholder groups will have the right to require us to purchase all (but not less than all) of its shares during the same period in which we can exercise our option. At the end of that period, if no stockholder has exercised its option, we will have a one-time option to purchase shares from the other stockholders to bring our holdings to 50.1% of the total outstanding shares. If we exercise our option or if all the stockholder groups exercise their put rights, the purchase price for 70% of the remaining 50.1% of the Sithe stock will be set at a fair market value plus a 10% premium in the case of a call or 10% discount in the case of a put, subject to a floor of $430 million and a ceiling of $650 million, and the remaining portion will be valued at fair market value subject to floor price of $141 million and a ceiling price of $330 million, plus, in each case, interest accrued from the beginning of the exercise period.

Effective April 1, 2001, Exelon Generation changed its accounting estimates related to the depreciation and decommissioning of certain generating stations. The estimated service lives were extended by 20 years for three nuclear stations, by periods of up to 20 years for certain fossil stations and by 50 years for a pumped storage station. Effective July 1, 2001, the estimated service lives were extended by 20 years for the remainder of Exelon Generation's operating nuclear stations. These changes were based on engineering and economic feasibility studies performed by Exelon Generation considering, among other things, future capital and maintenance expenditures at these plants. The extension of the estimated service lives for the nuclear generating facilities is subject to approval by the NRC. As a result of the change, depreciation and decommissioning expense for 2001 decreased $90 million ($54 million, net of income taxes). At the end of the year, annualized savings resulting from the change would be a decrease of $132 million ($79 million, net of income taxes).

The [officers and employees] of the registrant are insured under policies of insurance, within the limits and subject to the limitations of the policies, against claims made against them for acts in the discharge of their duties, and the registrant is insured to the extent that it is required or permitted by law to indemnify the [officers and employees] for such loss. The premiums for such insurance are paid by the registrant.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes to file an application for the purpose of determining the eligibility of the trustee to act under subsection (a) of Section 310 of the Trust Indenture Act in accordance with the rules and regulations prescribed by the Commission under Section 305(b)(2) of the Act.

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant, Exelon Generation Company, LLC, certifies that it has reasonable grounds to believe it meets all of the requirements for filing on Form S-4 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Kennett Square, Commonwealth of Pennsylvania, on this day of April, 2002.

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Oliver D. Kingsley, Jr. and John L. Settelen, Jr. and each or any one of them, his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this registration statement and any registration statement relating to any offering made pursuant to this registration statement that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or his or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Pennsylvania	4911	23-3064219
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

Edward J. Cullen, Jr.,				Robert C. Gerlach Lisa M. Sloan
Vice President & General Counsel 300 Exelon Way Kennett Square, Pennsylvania 19348 (610)765-5700		and		c/o Ballard Spahr Andrews & Ingersoll, LLP 1735 Market Street Philadelphia, Pennsylvania 19103 (215)864-8526 (215)864-8638

Title of Each Class of Securities to be Registered	Amount to be Registered	Proposed Maximum Offering Price Per Unit(2)	Proposed Maximum Aggregate Offering Price(2)	Amount of Registration Fee


6.95% Senior Notes due 2011 (Exchange Notes)	$700,000,000	100%	$700,000,000	$64,400

The Exchange Offer	We are offering to exchange an aggregate of $700,000,000 principal amount of exchange notes in one series, for the $700,000,000 6.95% Senior Notes due 2011. The original notes may be exchanged only in minimum denominations of $1,000 and multiples thereof.
The Original Notes	The original notes were issued and sold on June 14, 2001 in a transaction not requiring registration under the Securities Act. At the time we issued the original notes, we entered into a registration rights agreement which obligates us to make this exchange offer.
Required Representations	In order to participate in the exchange offer, you will be required to make some representations in a letter of transmittal, including that:
	•	you are not affiliated with us,
	•	you are not a broker-dealer who bought your original notes directly from us,
	•	you will acquire the exchange notes in the ordinary course of business, and
	•	you have not agreed with anyone to distribute the exchange notes.
	If you are a broker-dealer that purchased original notes for your own account as part of market-making or trading activities, you must represent to us that you have agreed with us or our affiliates not to distribute the exchange notes. If you make this representation, you need not make the last representation provided for above. Each broker-dealer that receives exchange notes for its own account in exchange for original notes, where the original notes were acquired by the broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of exchange notes. See "Plan of Distribution."

Resale of the Exchange Notes		We are making the exchange offer in reliance on the position of the staff of the Division of Corporation Finance of the SEC outlined in certain interpretive letters issued to other companies in other transactions. We believe that the exchange notes acquired in this exchange offer may be freely traded without compliance with the provisions of the Securities Act that call for registration and delivery of a prospectus, except as described in the following paragraph.
		The exchange notes will be freely tradable only if the holders meet the conditions described under "Required Representations" above. If you are a broker-dealer that purchased original notes for your own account as part of market-making or trading activities, you must deliver a prospectus when you sell the exchange notes. We have agreed in the registration rights agreement relating to the original notes to allow you to use this prospectus for this purpose during the one-year period following the Expiration Date, subject to our right under some circumstances to restrict your use of this prospectus. See "The Exchange Offer—Resales of Exchange Notes."
		Broker-dealers that acquired original notes directly from us may not rely on the staff's interpretations and must comply with the registration and prospectus delivery requirements of the Securities Act, including being named as a selling security holder, in order to resell the original notes or the exchange notes.
Accrued Interest on the Exchange Notes		The exchange notes will bear interest at an annual rate of 6.95%. Any interest that has accrued on the original notes before their tender in this exchange offer will be payable on the exchange notes on the first interest payment date after the conclusion of this exchange offer.
Procedures for Exchanging Notes		The procedures for exchanging original notes involve notifying the exchange agent before the Expiration Date of your intention to do so. These procedures are described in this prospectus under the heading "The Exchange Offer—Procedures for Tendering Original Notes."
Expiration Date		5:00 p.m., Eastern Time, on , 2002, unless the exchange offer is extended (the "Expiration Date").
Exchange Date		We will notify the exchange agent of the date of acceptance of the original notes for exchange.
Withdrawal Rights		If you tender your original notes for exchange in this exchange offer and later wish to withdraw them, you may do so at any time before 5:00 p.m., Eastern Time, on the Expiration Date.
Acceptance of Original Notes and Delivery of Exchange Notes		We will accept any original notes that are properly tendered for exchange before 5:00 p.m., Eastern Time, on the Expiration Date. The exchange notes will be delivered promptly after the Expiration Date.

Tax Consequences		You will not incur any material federal income tax consequences from your participation in this exchange offer. The exchange of notes will not constitute a taxable exchange for United States federal income tax purposes. For a discussion of other United States federal income tax consequences resulting from the exchange and the acquisition, ownership and disposition of the exchange notes, see "Certain U.S. Federal Income Tax Considerations."
Use of Proceeds		We will not receive any cash proceeds from this exchange offer.
Exchange Agent		Wachovia Bank, National Association is serving as the exchange agent. Its address and telephone number are provided in this prospectus under the heading "The Exchange Offer—Exchange Agent."
Effect on Holders of Original Notes		Any original notes that remain outstanding after this exchange offer will continue to be subject to restrictions on their transfer. The original notes may not be offered or sold in the United States for the account of or benefit of United States persons within the meaning of the Securities Act, except pursuant to an exemption from or in a transaction not subject to, the registration requirements of the Securities Act. After this exchange offer, holders of original notes will not (with limited exceptions) have any further rights under the registration rights agreement. Any market for original notes that are not exchanged could be adversely affected by the consummation of this exchange offer.

Issuer	Exelon Generation Company, LLC
Securities Offered	$700,000,000 6.95% Senior Notes due 2011 (Exchange Notes) which have been registered under the Securities Act.
Interest Payment Dates	June 15 and December 15 of each year, beginning June 15, 2002.
Maturity	June 15, 2011.
Optional Redemption	We may, at our option, redeem the exchange notes in whole or in part at any time at a price equal to the greater of (i) 100% of the principal amount of the exchange notes being redeemed plus accrued interest to the redemption date or (ii) as determined by the reference treasury dealer appointed by us, the sum of the present values of the remaining scheduled payments of principal and interest on the exchange notes to be redeemed (not including any portion of payments of interest accrued as of the redemption date) discounted to the redemption date on a semi-annual basis at the Adjusted Treasury Rate plus 25 basis points, plus accrued interest to the redemption date. See "Description of Exchange Notes—Redemption at Our Option."
Ranking	The exchange notes will be unsecured obligations and will rank equally with all of our unsecured and unsubordinated debt. As of December 31, 2001, we had outstanding approximately $1.03 billion of debt (including the original notes) that ranked equally with the exchange notes.
Ratings	It is anticipated that the exchange notes will be rated "Baa1" by Moody's Investors Service, Inc., "BBB+" by Fitch, Inc. and "A-" by Standard & Poor's Ratings Services.
	A security rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
Certain Covenants	The indenture under which the exchange notes will be issued limits our ability to, among other things,
	•	engage in mergers, consolidations or similar transactions;
	•	create liens;
	•	sell property and assets (except under certain circumstances); and
	•	engage in sale and leaseback transactions.
	Each of these covenants is subject to a number of important qualifications and exceptions. See "Description of the Exchange Notes—Certain Covenants."
Form	The exchange notes will be book-entry only and registered in the name of a nominee of DTC.

		As of December 31, 2001
		(in millions)
Current Portion of Long-Term Debt		$	4
Long-Term Debt:
	Senior Notes due 2011		699
	Other Long-Term Debt		322

Total Debt			1,025
Total Member's Equity			2,936

Total Capitalization		$	3,961

							Components of Variance
	2001		2000		Variance		Merger Variance		Normal Operations
	(in millions)
Operating Revenue	$	7,048	$	3,274	$	3,774	$	2,772	$	1,002

Fuel & Purchased Power		4,218		1,846		2,372		1,689		683
Operating & Maintenance and Other		1,586		858		728		978		(250	)
Depreciation & Decommissioning		282		123		159		83		76

EBIT	$	962	$	447	$	515	$	22	$	493

			Payment Due within
Obligations/Commitments			Payment Due within						Due After 5 Years
Obligations/Commitments	Total		1 Year		2-3 Years		4-5 Years		Due After 5 Years
	($ in millions)
Long-Term Debt(a)	$	1,025	$	4	$	5	$	—	$	1,016
Operating Leases(b)		682		28		63		64		527
Purchase Power Obligations(c)		12,192		1,695		3,173		1,346		5,978
Acquisition of TXU Generating Stations(d)		443		443		—		—		—
Spent fuel obligation(e)		843								843

	Non-trading			Trading
	(in millions)
Fair value of contracts outstanding as of January 1, 2001 (Reflects the adoption of SFAS No. 133)	$	(7	)		—
Change in fair value during 2001:
Contracts settled during year		87			7
Mark-to-market unrealized gain (loss)		(2	)		7

Total change in Fair Value		85			14

Fair value of contracts outstanding at December 31, 2001	$	78		$	14

	Non-trading		Trading
Mark-to-market gain on non-qualifying hedge contracts or hedge ineffectiveness reflected in earnings	$	16	$	14
Mark-to market hedge contracts reflected in Other Comprehensive Income		69		—

Total change in fair value	$	85	$	14

		Less than One Year			One - Three Years		Three - Five Years			Total Fair Value
		(in millions)
Non-trading:
Actively quoted prices		$	—		$	—	$	—		$	—
Prices provided by other external sources			36			50		—			86
Prices based on model or other valuation methods			(4	)		2		(6	)		(8	)

	Total	$	32		$	52	$	(6	)	$	78

Trading:
Actively quoted prices		$	—		$	—	$	—		$	—
Prices provided by other external sources			10			4		—			14
Prices based on model or other valuation methods			—			—		—			—

	Total	$	10		$	4	$	—		$	14

Fuel/Technology		Station	Location	No. of Units	% Owned(1)	Primary Fuel Type	Dispatch Type	Net Generation Capacity (MW)(2)
Nuclear(3)		Braidwood	Braidwood, IL	2		Uranium	Base-load	2,372
		Byron	Byron, IL	2		Uranium	Base-load	2,391
		Dresden	Morris, IL	2		Uranium	Base-load	1,659
		LaSalle County	Seneca, IL	2		Uranium	Base-load	2,298
		Limerick	Limerick Twp., PA	2		Uranium	Base-load	2,312
		Peach Bottom	Peach Bottom Twp., PA	2	50.00	Uranium	Base-load	1,112	(4)
		Quad Cities	Cordova, IL	2	75.00	Uranium	Base-load	1,172	(4)
		Salem	Hancock's Bridge, NJ	2	42.59	Uranium	Base-load	934	(4)

								14,250
Fossil		Cromby 1	Phoenixville, PA	1		Coal	Base-load	144
(Steam Turbines)		Cromby 2	Phoenixville, PA	1		Oil/Gas	Intermediate	201
		Delaware	Philadelphia, PA	2		Oil	Peaking	250
		Eddystone 1, 2	Eddystone, PA	2		Coal	Base-load	581
		Eddystone 3, 4	Eddystone, PA	2		Oil/Gas	Intermediate	760
		Schuylkill	Philadelphia, PA	1		Oil	Peaking	166
		Conemaugh	New Florence, PA	2	20.72	Coal	Base-load	352	(4)
		Keystone	Shelocta, PA	2	20.99	Coal	Base-load	357	(4)
		Fairless Hills	Falls Twp., PA	2		Landfill Gas	Peaking	60

								2,871
Fossil		Chester	Chester, PA	3		Oil	Peaking	39
(Combustion		Croydon	Bristol Twp., PA	8		Oil	Peaking	380
Turbines)		Delaware	Philadelphia, PA	4		Oil	Peaking	56
		Eddystone	Eddystone, PA	4		Oil	Peaking	60
		Falls	Falls Twp., PA	3		Oil	Peaking	51
		Moser	Lower Pottsgrove Twp., PA	3		Oil	Peaking	51
		Pennsbury	Falls Twp., PA	2		Landfill Gas	Peaking	6
		Richmond	Philadelphia, PA	2		Oil	Peaking	96
		Schuylkill	Philadelphia, PA	2		Oil	Peaking	30
		Southwark	Philadelphia, PA	4		Oil	Peaking	52
		Salem	Hancock's Bridge, NJ	1	42.59	Oil	Peaking	16	(4)
		LaPorte	LaPorte, TX	4		Gas	Peaking	160

								997
Fossil		Cromby	Phoenixville, PA	1		Oil	Peaking	3
(Internal		Delaware	Philadelphia, PA	1		Oil	Peaking	3
Combustion/Diesel)		Schuylkill	Philadelphia, PA	1		Oil	Peaking	3
		Conemaugh	New Florence, PA	4	20.72	Oil	Peaking	2	(4)
		Keystone	Shelocta, PA	4	20.99	Oil	Peaking	2	(4)

								13
Hydroelectric		Conowingo	Harford Co., MD	11		Hydro	Base-load	512
Pumped Storage		Muddy Run	Lancaster Co., PA	8		Hydro	Intermediate	1,072

								1,584
	Total			101				19,715

Seller	Location	Capacity (MW)	Expiration
Midwest Generation, LLC	Various in Illinois	9,105	2004
Kincaid Generation, LLC	Kincaid, Illinois	1,158	2012
Tenaska Georgia Partners, LP	Franklin, Georgia	900	2029
Tenaska Frontier, Ltd	Shiro, Texas	830	2020
Others	Various	4,252	2002 to 2022

Total		16,245

(in millions)	Capacity Purchases		Power Only Purchases		Power-Only Sales		Transmission Rights Purchases
2002	$	1,005	$	551	$	1,803	$	139
2003		1,214		345		666		11
2004		1,222		346		219		15
2005		406		264		139		15
2006		406		250		58		5
Thereafter		3,657		2,321		22		—

Total	$	7,910	$	4,077	$	2,907	$	205

	A N N U A L C O M P E N S A T I O N						L O N G T E R M C O M P E N S A T I O N
							Awards
		Bonus					Awards		Payouts
		Bonus					Restricted Stock Awards ($)		Payouts				All Other Compen- sation ($)
Name and Principal Position	Year	Salary ($)	Cash ($)	Stock- Based ($)(1)		Other ($)(2)	Restricted Stock Awards ($)	Options (#)(3)	Cash ($)		Stock- Based ($)(1)		All Other Compen- sation ($)
Corbin A. McNeill, Jr. Chief Executive Officer & President,	2001 2000 1999	1,050,000 855,830 659,857	1,500,300 1,081,472 1,000,000	— — —		84,987	1,354,104 2,803,513 942,188	233,000 392,500 —	— — —		— — —		26,573 3,200 3,200
John W. Rowe Co-CEO & President, Exelon Corp.	2001 2000 1999	1,050,000 989,423 957,692	1,500,300 1,180,269 529,125	— — 529,125	*	71,369 134,473 55,112	1,354,104	233,000 385,450 116,850	— 1,071,878 475,246	*	— 1,071,878 203,667	* *	52,729 60,293 42,478
Oliver D. Kingsley, Jr. President & Chief Nuclear Officer, Exelon Nuclear	2001 2000 1999	650,000 609,615 544,385	928,000 677,354	— — 594,000	*	98,677 175,502	597,729 231,562	— 223,250 38,000	— 547,251 —		— 547,251 322,488	* *	32,499 37,745 24,139
John L. Skolds(4) Chief Operating Officer, Exelon Nuclear	2001 2000 1999	430,000 157,115	483,900 441,306	— — —		59,772 130,466	353,750 453,750	45,000 107,075 —	— — —		— 617,465 —	*	21,499 5,755 —
Ian P. McLean(5) President, Exelon Power Team	2001 2000 1999	362,311 308,000 72,692	323,100 220,596 63,900	— — —		134,267 — —	261,042 429,600 1,105,625	49,644 83,000 125,000	149,160 — —		— — —		683 — —

Type of Plant	Station	Location	No. of Units	Fuel	Dispatch Type	Net Generation Capacity (MW)
Merchant Plants	Batavia	New York	1	Gas	Intermediate	50
	ForeRiver 1, 2	Massachusetts	2	Oil	Peaking	26
	Framingham 1, 2, 3	Massachusetts	3	Oil	Peaking	37
	Massena	New York	1	Gas/Oil	Intermediate	66
	Mystic 4, 5, 6, 7	Massachusetts	4	Oil	Intermediate	995
	Mystic CT	Massachusetts	1	Oil	Peaking	11
	New Boston 1, 2	Massachusetts	2	Gas/Oil	Intermediate	760
	New Boston 3	Massachusetts	1	Oil	Peaking	20
	Ogdensburg	New York	1	Gas/Oil	Intermediate	71
	West Medway 1, 2, 3	Massachusetts	3	Gas/Oil	Peaking	165
	Wyman 4	Maine	1	Oil	Intermediate	36
	Cardinal	Canada	1	Gas	Base-load	157
Qualifying Facilities	Allegheny 5, 6, 8, 9	Pennsylvania	4	Hydro	Intermediate	51
	Bypass	Idaho	1	Hydro	Base-load	10
	Elk Creek	Idaho	1	Hydro	Base-load	2
	Greeley	Colorado	1	Gas	Base-load	48
	Hazelton	Idaho	1	Hydro	Base-load	9
	Independence	New York	1	Gas	Base-load	614
	Ivy River	North Carolina	1	Hydro	Base-load	1
	Kenilworth	New Jersey	1	Gas/Oil	Base-load.	26
	Montgomery Creek	California	1	Hydro	Base-load	3
	Naval Station	California	1	Gas/Oil	Base-load	45
	Naval Training Center	California	1	Gas/Oil	Base-load	23
	North Island	California	1	Gas/Oil	Base-load	37
	Oxnard	California	1	Gas	Base-load	48
	Rock Creek	California	1	Hydro	Base-load	4
	Sterling	New York	1	Gas	Intermediate	56
Under Construction	ForeRiver 3	Massachusetts	1	Gas/Oil	Base-load	807
	Mystic 8, 9	Massachusetts	2	Gas	Base-load	1,614
	TEG 1, 2	Mexico	2	Coke	Base-load	230
Under Advanced Development	Heritage 1, 2	New York	2	Gas	Base-load	800
	Goreway	Canada	1	Gas	Base-load	800
	Southdown	Canada	1	Gas	Base-load	800

Total			48			8,422

Station	Year Acquired	Location	Net Generation Capacity (MW)	License Expiration Date(1)
Clinton Nuclear Power Station	1999	Clinton, IL	933	2026
Unit 1 of Three Mile Island ("TMI") Nuclear Station	1999	Londonderry Twp., PA	835	2014
Oyster Creek Nuclear Generation Facility	2000	Forked River, NJ	630	2009

Total			2,398

	Individual Grants						Grant Date Value
Name	Number of Securities Underlying Options Granted(#)(1)	% of Total Options Granted to Employees in 2000		Exercise or Base Price ($/Sh.)		Expiration Date	Grant Date Present Value ($)
Corbin A. McNeill, Jr.	233,300	37.08	%	$	67.88	01/01/2011	$	4,710,327
John W. Rowe	233,300	37.08	%	$	67.88	01/01/2011	$	4,710,327
Oliver D. Kingsley, Jr.	0
John L. Skolds	0
Ian P. McLean	0

		Divisional Equity			Membership Interest			Undistributed Earnings		Accumulated Other Comprehensive Income			Total Divisional/ Member's Equity
Balance, January 1, 1999		$	746		$	—		$	—	$	—		$	746
	Net income		204											204

Balance, December 31, 1999			950											950

	Net income		260											260
	Contribution of net assets as a result of merger with Unicom		1,400											1,400

Balance, December 31, 2000			2,610											2,610

	Formation of LLC		(2,610	)		2,610								—
	Non-cash distribution to member					(174	)							(174	)
	Net income								524					524
	Distribution to member					(121	)							(121	)
	Reclassified net unrealized losses on marketable securities, net of income taxes of $22										(23	)		(23	)
	Comprehensive income, net of income tax benefit of $171										120			120

Balance, December 31, 2001		$	—		$	2,315		$	524	$	97		$	2,936

	2001
Plant	2001
Plant	Peach Bottom			Salem			Keystone			Conemaugh			Quad Cities
Operator	Exelon Generation			PSEG Nuclear			Sithe			Sithe			Exelon Generation
Participating Interest		50.00	%		42.59	%		20.99	%		20.72	%		75.00	%
Generation plant	$	387		$	12		$	121		$	193		$	96
Construction work-in-progress		13			53			13			12			52

Total property, plant and equipment		400			65			134			205			148
Accumulated depreciation		220			4			98			124			10

Property, plant and equipment, net	$	180		$	61		$	36		$	81		$	138

					December 31,
				Maturity Date	December 31,
		Rates		Maturity Date	2001			2000
Notes payable		7.25	%	2003-2004	$	9		$	14
Senior unsecured notes		6.95	%	2011		699			—
Pollution control notes		2.10%—2.70	%	2016-2034		317			195

	Total long-term debt					1,025			209
Due within one year						(4	)		(4	)

	Long-term debt				$	1,021		$	205

		2001			2000
Deferred tax assets:
	Decommissioning and decontamination obligations	$	856		$	455
	Deferred pension and postretirement obligations		236			227
	Deferred investment tax credits		93			96
	Other, net					110

Total deferred tax assets			1,185			888

Deferred tax liabilities:
	Plant basis difference		(709	)		(397	)
	Unrealized gains on derivative financial instruments		(30	)		—
	Decommissioning and decontamination obligations		(100	)		(118	)
	Emission allowances		(44	)		(36	)
	Other, net		(12	)		—

Total deferred tax liabilities			(895	)		(551	)

Deferred income taxes net on the balance sheet		$	290		$	337

Sensitivity of retiree welfare results
Effect of a one percentage point increase in assumed health care cost trend on total service and interest cost components	$	15
on postretirement benefit obligation	$	135
Effect of a one percentage point decrease in assumed health care cost trend on total service and interest cost components	$	(12	)
on postretirement benefit obligation	$	(117	)

		(in millions)
Production Plant		$	392
Nuclear Fuel			432
Investments			254

	Total	$	1,078

		Unaffiliated								Affiliated
		Power Purchases		Power Sales		Capacity Purchases		Transmission Rights Purchases		Power Sale/ Capacity		Power Purchases
2002		$	295	$	1,803	$	1,005	$	139	$	4,047	$	256
2003			84		666		1,214		31		4,220		261
2004			31		219		1,222		15		4,094		315
2005			23		139		406		15		4,018		241
2006			9		58		406		5		3,974		241
Thereafter			150		22		3,657		—		6,207		2,171

	Total	$	592	$	2,907	$	7,910	$	205	$	26,560	$	3,485

		2001		2000
		Carrying Amount	Fair Value	Carrying Amount		Fair Value
Non-derivatives
Assets:
	Cash and cash equivalents	224	224	4		4
	Customer accounts receivable	316	316	316		316
	Nuclear decommissioning trust funds	3,165	3,165	3,127		3,127
Liabilities:
	Long-term debt (including amounts due within one year)	1,025	1,040	209		209
Derivatives
	Energy Derivatives	92	92	(34	)	(34	)

		December 31, 2001
		Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
Equity securities		$	1,666	$	130	$	(236	)	$	1,560

Debt securities:
	Government obligations		882		28		(3	)		907
	Other debt securities		701		16		(19	)		698

Total debt securities			1,583		44		(22	)		1,605

Total available-for-sale securities		$	3,249	$	174	$	(258	)	$	3,165

	For the years ended December 31,
	2001			2000
Proceeds from sales	$	1,624		$	265
Gross realized gains		76			9
Gross realized losses		(189	)		(46	)

	Calendar Quarter Ended
	March 31,				June 30,				September 30,				December 31,
	2001		2000		2001		2000		2001		2000		2001		2000
Revenues	$	1,628	$	510	$	1,618	$	645	$	2,292	$	941	$	1,510	$	1,178
Operating income	$	268	$	70	$	113	$	140	$	225	$	228	$	266	$	3
Income before cumulative effect of change in accounting principle	$	158	$	88	$	71	$	147	$	167	$	164	$	116	($	139	)
Cumulative effect of a change in accounting principle	$	12		—		—		—		—		—		—		—
Net income (loss)	$	170	$	88	$	71	$	147	$	167	$	164	$	116	($	139	)

	December 31,
	2001		2000
Valuation Allowances
Allowance for Doubtful Accounts	$	17	$	2
Reserve for inventory obsolescence	$	12	$	79
Accumulated Amortization
Nuclear Fuel	$	1,838	$	1,445

Exhibit Number		Description
3.1		Certificate of Formation of Exelon Generation Company, LLC.
3.2		Exelon Generation Company, LLC Operating Agreement.
4.1		Indenture dated June 1, 2001 between Registrant and First Union National Bank (now Wachovia Bank, National Association).
4.2		Registration Rights Agreement dated June 29, 2001 between Registrant and the purchasers named therein.
4.3		Form of 6.95% Exchange Note.
5		Opinion of Ballard Spahr Andrews & Ingersoll, LLP.
8		Opinion of Ballard Spahr Andrews & Ingersoll, LLP regarding tax matters.
10.1		Power Purchase Agreement among Registrant and PECO
10.2		Power Purchase Agreement among Registrant and ComEd.
12		Statement regarding computation of ratios of earnings.
23.1		Consent of Ballard Spahr Andrews & Ingersoll, LLP (contained in Exhibits 5 and 8).
23.2		Consent of Independent Accountants.
24		Power of Attorney.
25		Statement of Eligibility of Trustee on Form T-1.
99.1		Form of Letter of Transmittal.
99.2		Form of Notice of Guaranteed Delivery
99.3		Client Letter
99.4		Broker-Dealer Letter
99.5		Form W-9

Exelon Generation Company, LLC
By:	Exelon Ventures Company, LLC, a Delaware limited liability company, as the Managing Member
By:	Exelon Corporation, a Pennsylvania corporation, as the Managing Member
	/s/ OLIVER D. KINGSLEY, JR.
	Name:	Oliver D. Kingsley, Jr.
	Title:	Senior Vice President

Signature	Date	Title

/s/ OLIVER D. KINGSLEY, JR. Oliver D. Kingsley, Jr.	April , 2002	Chief Executive Officer and President, Exelon Generation Company, LLC
/s/ JOHN L. SETTELEN, JR. John L. Settelen, Jr.	April , 2002	Vice President and Controller, Exelon Generation Company, LLC (Principal Financial Officer)

Exhibit Number		Description
3.1		Certificate of Formation of Exelon Generation Company, LLC.
3.2		Exelon Generation Company, LLC Operating Agreement.
4.1		Indenture dated June 1, 2001 between the Registrants and First Union National Bank (now Wachovia Bank, National Association).
4.2		Registration Rights Agreement dated June 29, 2001 between the Registrant and the purchasers named therein.
4.3		Form of 6.95% Exchange Note.
5		Opinion of Ballard Spahr Andrews & Ingersoll, LLP.
8		Opinion of Ballard Spahr Andrews & Ingersoll, LLP regarding tax matters.
10.1		Power Purchase Agreement among Registrant and PECO
10.2		Power Purchase Agreement among Registrant and ComEd.
12		Statement regarding computation of ratios of earnings.
23.1		Consent of Ballard Spahr Andrews & Ingersoll, LLP (contained in Exhibits 5 and 8).
23.2		Consent of Independent Accountants.
24		Power of Attorney.
25		Statement of Eligibility of Trustee on Form T-1.
99.1		Form of Letter of Transmittal.
99.2		Form of Notice of Guaranteed Delivery
99.3		Client Letter
99.4		Broker-Dealer Letter
99.5		Form W-9