We depend on transmission availability.

        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 transmissioncoverages, 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

9

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 a limited operating history as a stand-alone power generator.

        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.

We are subject to control by Exelon.

        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.

Conflicts of interest may arise between us and our affiliates.

        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.

There is no public market for the exchange notes.

        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

10

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.

FORWARD-LOOKING STATEMENTS

        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.

•

the significant considerations and risks discussed in this prospectus;



•

general and local economic, market or business conditions;



•

fluctuations in demand for electricity, capacity and ancillary services in the markets in which we operate;



•

increasing competition from other companies;



•

the acquisition and development opportunities (or lack thereof) that may be presented to and pursued by us;



•

changes in laws or regulations that are applicable to us;



•

environmental constraints on construction and operation;



•

the rapidly changing market for energy products; and



•

access to capital.

        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.

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USE OF PROCEEDS

        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.

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CAPITALIZATION

        The following table sets forth our capitalization as of December 31, 2001.

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

        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.

(1)

EBIT is earnings before interest and income taxes, earnings from equity investments, and other income and expense recorded in other, net, with exception of interest income. EBITDA is EBIT plus depreciation and decommissioning, plus amortization of nuclear fuel. EBIT and EBITDA may differ from the calculations used by other companies and should not be considered as an alternative to net income, cash flows or any other item calculated in accordance with United States generally accepted accounting principles or as an indication of operating performance or liquidity.

(2)

The Ratio of Earnings to Fixed Charges is calculated by dividing earnings by fixed charges. For this purpose "earnings" means pre-tax income from continuing operations before adjustment for income or loss from equity investees. "Fixed Charges" means interest costs and amortization of debt discount and premium on all indebtedness and rentals for operating leases.

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

Results of Operations

Year Ended December 31, 2001 Compared to Year Ended December 31, 2000

        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.

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        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:

        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.

Other Components of Net Income

        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.

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Cumulative Effect of Changes in Accounting Principles

        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.

Year Ended December 31, 2000 Compared to Year Ended December 31, 1999

        Net Income.    Our net income increased $56 million, or 27%, in 2000.

        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.

Other Components of Net Income

        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.

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Liquidity and Capital Resources

        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%.

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        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:

(a)

Comprised primarily of senior unsecured debt and pollution control notes. In connection with the variable rate debt we maintain direct pay letters of credit in order to provide liquidity in the event that it is not possible to remarket all of the debt as required following specific events, including changes in the basis of determining the interest rate of debt. Letters of credit as of December 31, 2001 amounted to $317 million of which $121 million expire in 2002 and the remaining $196 million expire in 2003 to 2004. Total includes the current portion of long-term debt.

(b)

Company leases equipment and certain office facilities.

(c)

Commitments relating to the purchase of energy, capacity and transmission rights. Include in amounts are $3,485 million of dollars power purchases from our affiliate AmerGen.

(d)

Commitment to purchase generating stations in spring of 2002.

(e)

One-time fee of $277 million with interest to date payable to the DOE for Spent Nuclear Fuel.

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        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.

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Quantitative and Qualitative Disclosures About Market Risk

        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

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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

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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

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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.

Critical Accounting Policies

        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

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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).

Outlook

        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

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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.

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NEIL has made distributions to its members. Our distributionpower plants. Based on estimates of decommissioning costs for 2001 was $69 million,each of the nuclear facilities in 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 insurancehave an ownership interest, 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 formerAmerGen facilities, 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.

New Accounting Pronouncements

        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,

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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.

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BUSINESS

Overview

        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.

Business Strategy

        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;



•

drive cost and operational leadership through proven fleet management and economies of scale; and



•

optimize the value of our low-cost generation portfolio through our power marketing expertise.

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        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.

Competitive Strengths

        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;



•

operating experience and expertise;



•

critical mass of generation capacity with economies of scale;



•

stable revenue streams under long-term contracts with ComEd and PECO; and



•

extensive experience in the wholesale power markets.

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        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.

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Overview of Generation Assets and Investments

        Our generation assets and investments consist of the following:

(1)

See "Fuel" for sources for fuels used in electric generation.

(2)

Based on Generation's ownership.

(3)

Contracts range from 1 to 29 years.

        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.

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

Overview of Power Marketing

        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.

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Owned Generation Assets

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

(1)

100%, unless otherwise indicated.

(2)

For nuclear stations, except Salem, capacity reflects the annual mean rating. All other stations, including Salem, reflect a summer rating.

(3)

All nuclear stations are boiling water reactors except Braidwood, Byron and Salem, which are pressurized water reactors.

(4)

Generation's portion.

        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.

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Nuclear Facilities

        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.

(1)

The capacity factors for 1997 through 1999 reflect the shutdown of LaSalle and Zion for portions of the period.

        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.

        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.

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        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.

Fossil and Hydroelectric Facilities

        Our fossil units include:

•

base-load units—the coal-fired units at Eddystone and Cromby and our interests in the Keystone and Conemaugh Stations;



•

intermediate units—the Eddystone and Cromby units that have dual fuel (oil/gas) capability; and



•

peaking units—oil- or gas-fired steam turbines, combustion turbines and internal combustion units at various locations.

        Our hydroelectric facilities include:

•

base-load units—at the Conowingo run-of-river hydroelectric facility on the Susquehanna River in Harford County, Maryland; and



•

intermediate units—at the Muddy Run pumped-storage hydroelectric facility in Lancaster County, Pennsylvania.

        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.

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        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.

Long-Term Contracts

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

        In 2001, approximately 37% of our sales were of purchased power.

Midwest Generation Contract

        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.

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Investments

Sithe Energies, Inc.

        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.

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        The following table shows Sithe's principal assets as of December 31, 2001.