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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

COMMONWEALTH EDISON COMPANY:
Common Stock Purchase Warrants, 1971 Warrants and Series B Warrants

PECO ENERGY COMPANY:
Cumulative Preferred Stock, $7.48 Series without par value

        Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes ý No o

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

        Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

        The estimated aggregate market value of the voting and non-voting common equity held by nonaffiliates of each registrant as of June 28, 2002, was as follows:

        The number of shares outstanding of each registrant's common stock as of February 28, 2003 was as follows:

Other

        Exelon Generation Company, LLC meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format.

DOCUMENTS INCORPORATED BY REFERENCE:

        Portions of Exelon Corporation's Current Report on Form 8-K dated February 21, 2003 containing consolidated financial statements and related information for the year ended December 31, 2002, are incorporated by reference into Parts II and IV of this Annual Report on Form 10-K. Portions of Exelon Corporation's definitive Proxy Statement filed on March 13, 2003 relating to its annual meeting of shareholders, are incorporated by reference into Part III of this Annual Report on Form 10-K.

        Portions of Commonwealth Edison Company's definitive Information Statement to be filed prior to April 30, 2003, relating to its annual meeting of shareholders, are incorporated by reference into Part III of this Annual Report on Form 10-K.

        Portions of PECO Energy Company's definitive Information Statement to be filed prior to April 30, 2003, relating to its annual meeting of shareholders, are incorporated by reference into Part III of this Annual Report on Form 10-K.

        This combined Form 10-K is separately filed by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC (Registrants). Information contained herein relating to any individual registrant is filed by such registrant in its own behalf. No registrant makes any representation as to information relating to any other registrant.

TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS

        Except for the historical information contained herein, certain of the matters discussed in this Report are forward-looking statements that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by a registrant include those discussed herein, including those discussed in (a) ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Business Outlook and the Challenges in Managing Our Business for Exelon, ComEd, PECO and Generation, (b) ITEM 8. Financial Statements and Supplementary Data: Exelon—Note 19, ComEd—Note 16, PECO—Note 18 and Generation—Note 13, and (c) other factors discussed in filings with the Securities and Exchange Commission (SEC) by Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC (Registrants). Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

WHERE TO FIND MORE INFORMATION

        The public may read and copy any reports or other information that the Registrants file with the SEC at the SEC's public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. These documents are also available to the public from commercial document retrieval services, the web site maintained by the SEC at http://www.sec.gov and Exelon Corporation's website at www.exeloncorp.com.

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PART I

ITEM 1. BUSINESS

General

        Exelon Corporation (Exelon) was incorporated in Pennsylvania in February 1999. On October 20, 2000, Exelon became the parent corporation for PECO Energy Company (PECO) and Commonwealth Edison Company (ComEd) as a result of a merger among PECO, Unicom Corporation (Unicom), the former parent company of ComEd, and Exelon (Merger). The Merger was accounted for using the purchase method of accounting with PECO as the acquiring company. Accordingly, Exelon's results of operations for 2000 consist of PECO's results of operations for 2000 and Unicom's results of operations after October 20, 2000.

        During January 2001, Exelon undertook a restructuring to separate its generation and other competitive businesses from its regulated energy delivery business at ComEd and PECO. As part of the restructuring, the generation-related operations and assets and liabilities of ComEd were transferred to Exelon Generation Company, LLC (Generation). Also, as part of the restructuring, the non-regulated operations and related assets and liabilities of PECO, representing PECO's generation and enterprises business segments, were transferred to Generation and Exelon Enterprises Company, LLC (Enterprises), respectively. Additionally, certain operations and assets and liabilities of ComEd and PECO were transferred to Exelon Business Services Company (BSC). BSC provides Exelon and its subsidiaries financial, human resource, legal, information technology, supply management and corporate governance services.

        Exelon, a registered public utility holding company, through its subsidiaries, operates in three business segments (see ITEM 8. Financial Statements and Supplementary Data—Exelon—Note 2 of the Notes to Consolidated Financial Statements):

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Energy Delivery, whose businesses include the regulated sale of electricity and distribution and transmission services by ComEd in northern Illinois and PECO in southeastern Pennsylvania and the sale of natural gas and distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia.



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Generation, consisting of the owned and contracted for electric generating facilities, energy marketing operations, and equity interests in Sithe Energies, Inc. (Sithe) and AmerGen Energy Company, LLC (AmerGen).



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Enterprises, consisting of competitive retail energy sales, energy and infrastructure services, communications and other investments (weighted towards the communications, energy services and retail services industries).

        Exelon's principal executive offices are located at 10 South Dearborn Street, Chicago, Illinois 60603, and its telephone number is 312-394-4321. ComEd was organized in the State of Illinois in 1913 as a result of the merger of Cosmopolitan Electric Company into the original corporation named Commonwealth Edison Company, which was incorporated in 1907. ComEd's principal executive offices are located at 10 South Dearborn Street, Chicago, Illinois 60603 and its telephone number is 312-394-4321. PECO was incorporated in Pennsylvania in 1929. PECO's principal executive offices are located at 2301 Market Street, Philadelphia, Pennsylvania 19101-8699 and its telephone number is 215-841-4000. Generation was formed in 2000 as a Pennsylvania limited liability company. Generation's principal executive offices are located at 300 Exelon Way, Kennett Square, Pennsylvania 19348 and its telephone number is 610-765-6900.

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        Exelon and several of its subsidiaries are subject to Federal and state regulation. Exelon is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). ComEd is a public utility under the Illinois Public Utilities Act subject to regulation by the Illinois Commerce Commission (ICC). PECO is a public utility under the Pennsylvania Public Utility Code subject to regulation by the Pennsylvania Public Utility Commission (PUC). PECO, ComEd and Generation are electric utilities under the Federal Power Act subject to regulation by the Federal Energy Regulatory Commission (FERC). Specific operations of Exelon are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the United States Nuclear Regulatory Commission (NRC).

        As a registered holding company, Exelon and its subsidiaries are subject to a number of restrictions under PUHCA. These restrictions generally involve financing, investments and affiliate transactions. Under PUHCA, Exelon and its subsidiaries cannot issue debt or equity securities or guarantees without approval of the Securities and Exchange Commission (SEC) or in some circumstances in the case of ComEd and PECO, the ICC or the PUC, respectively. Exelon currently has SEC approval to issue up to an aggregate of $4 billion in common stock, preferred securities, long-term debt and short-term debt, and to issue up to $4.5 billion in guarantees. PUHCA also limits the businesses in which Exelon may engage and the investments that Exelon may make. With limited exceptions, Exelon may only engage in traditional electric and gas utility businesses and other businesses that are reasonably incidental or economically necessary or appropriate to the operations of the utility business. The exceptions include Exelon's ability to invest in exempt telecommunications companies, in exempt wholesale generating businesses and foreign utility companies (these investments are capped at $4 billion in the aggregate), in energy-related companies (as defined in SEC rules, and subject to a cap on these investments of 15% of Exelon's consolidated capitalization), and in other businesses, subject to SEC approval. In addition, PUHCA requires that all of a registered holding company's utility subsidiaries constitute a single system that can be operated in an efficient, coordinated manner. For additional information about restrictions on the payment of dividends and other effects of PUHCA on Exelon and its subsidiaries, see ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Exelon.

Energy Delivery

        Energy Delivery consists of Exelon's regulated energy delivery operations conducted by ComEd and PECO.

        ComEd is engaged principally in the purchase, transmission, distribution and sale of electricity to a diverse base of residential, commercial, industrial and wholesale customers in northern Illinois. ComEd is subject to extensive regulation by the ICC as to rates, the issuance of securities, and certain other aspects of ComEd's operations. ComEd is also subject to regulation by FERC as to transmission rates and certain other aspects of its business.

        ComEd's retail service territory has an area of approximately 11,300 square miles and an estimated population of eight million as of December 31, 2002. The service territory includes the City of Chicago, an area of about 225 square miles with an estimated population of three million. ComEd had approximately 3.6 million customers at December 31, 2002.

        ComEd's franchises are sufficient to permit it to engage in the business it now conducts. ComEd's franchise rights are generally nonexclusive rights documented in agreements and, in some cases, certificates of public convenience issued by the ICC. With few exceptions, the franchise rights have stated expiration dates ranging from 2003 to 2050 and subsequent years.

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        PECO is engaged principally in the purchase, transmission, distribution and sale of electricity to residential, commercial and industrial customers in southeastern Pennsylvania and in the purchase, distribution and sale of natural gas to residential, commercial and industrial customers in the Pennsylvania counties surrounding the City of Philadelphia. PECO is subject to extensive regulation by the PUC as to electric and gas rates, the issuances of securities and certain other aspects of PECO's operations. PECO is also subject to regulation by FERC as to transmission rates, and certain other aspects of its business.

        PECO's retail service territory covers approximately 2,100 square miles in southeastern Pennsylvania. PECO provides electric delivery service in an area of approximately 2,000 square miles, with a population of approximately 3.8 million, including 1.5 million in the City of Philadelphia. Natural gas service is supplied in an approximate 2,100 square mile area in southeastern Pennsylvania adjacent to Philadelphia, with a population of approximately 2.3 million. PECO delivers electricity to approximately 1.5 million customers and natural gas to approximately 450,000 customers.

        PECO has the necessary franchise rights to furnish electric and gas service in the various municipalities or territories in which it now supplies such services. PECO's franchise rights, which are generally nonexclusive rights, consist of charter rights and certificates of public convenience issued by the PUC and/or "grandfather rights." Such franchise rights are generally unlimited as to time.

        As a result of Exelon's restructuring to separate its regulated and competitive businesses, effective January 1, 2001, both ComEd and PECO transferred their assets and liabilities unrelated to energy delivery to other subsidiaries of Exelon. In the case of ComEd, the assets and liabilities transferred included nuclear generation and wholesale power marketing operations and some administrative functions. In the case of PECO, the assets and liabilities transferred related to nuclear, fossil and hydroelectric generation and wholesale power marketing; unregulated ventures and activities, including communications, infrastructure services and unregulated gas and electric sales activities; and administrative, information technology and other support for other business activities of Exelon and its subsidiaries.

        Energy Delivery's kilowatthour (kWh) sales and load are generally higher, primarily during the summer periods but also during the winter periods, when temperature extremes create demand for either summer cooling or winter heating. ComEd's highest peak load experienced to date occurred on August 1, 2002 and was 21,804 megawatts (MWs), and the highest peak load experienced to date during a winter season occurred on December 20, 1999 and was 14,484 MWs. PECO's highest peak load experienced to date occurred on August 14, 2002 and was 8,164 MWs; and the highest peak load experienced to date during a winter season occurred on January 23, 2003 and was 6,346 MWs.

        PECO's gas sales are generally higher during the winter periods when temperature extremes create demand for winter heating. PECO's highest daily gas sendout experienced to date occurred on January 17, 2000 and was 718,362 thousand cubic feet.

Retail Electric Services

        Electric utility restructuring legislation was adopted in Pennsylvania in December 1996 and in Illinois in December 1997. Both Illinois and Pennsylvania permit competition by alternative generation suppliers for retail generation supply while transmission and distribution service remains fully regulated. Both states, through their regulatory agencies, established a phased approach for allowing customers to choose an alternative electric generation supplier, required rate reductions and imposed caps on rates during a transition period; and allowed the collection of competitive transition charges (CTCs) from customers to recover costs that might not otherwise be recovered in a competitive market (stranded costs).

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Under the restructuring initiatives adopted at the Federal and state levels, the role of electric utilities in the supply and delivery of energy is changing.

        Under Illinois and Pennsylvania legislation, ComEd and PECO are required to provide generation services to customers who do not or cannot choose an alternative supplier. Provider of last resort (POLR) obligations refer to the obligation of a utility to provide generation services (i.e., power and energy) to those customers who do not take service from an alternative generation supplier or who choose to come back to the utility after taking service from an alternative supplier. Because the choice lies with the customer, these obligations make it difficult for the utility to predict and plan for the level of customers and associated energy demand. If these obligations remain unchanged, the utility could be required to maintain reserves sufficient to serve 100% of the service territory load at a tariffed rate on the chance that customers who switched to new suppliers decide to come back to the utility as a "last resort" option. A significant over or under estimation of such reserves may cause commodity price risks for suppliers. ComEd and PECO continue to be obligated to provide a reliable delivery system under cost-based rates.

        Under terms of the 2001 corporate restructuring, ComEd remits to Generation any amounts collected from customers for nuclear decommissioning. Under an agreement effective September 2001, PECO remits to Generation any amounts collected from customers for nuclear decommissioning.

        ComEd.    As of December 31, 2002, all ComEd's customers are eligible to choose an alternative retail electric supplier (ARES) and non-residential customers can also elect the power purchase option (PPO) that allows the purchase of electric energy from ComEd at market-based prices. ComEd's residential customers became eligible to choose a new electric supplier in May 2002. However, as of December 31, 2002, no ARES had sought approval from the ICC and no electric utilities have chosen to enter the ComEd residential market for the supply of electricity. At December 31, 2002, approximately 22,700 non-residential customers, representing approximately 26% of ComEd's annual retail kilowatthour sales, had elected to purchase their electric energy from an ARES or had chosen the PPO. Customers who receive energy from an alternative supplier continue to pay a delivery charge. ComEd is unable to predict the long-term impact of customer choice on results of operations.

        In addition to retail competition for generation services, the Illinois legislation provided for residential base rate reductions, a sharing with customers of any earnings over a defined threshold and a base rate freeze, reflecting the residential base rate reductions, through January 1, 2007. A 15% residential base rate reduction became effective on August 1, 1998 and a further 5% residential base rate reduction became effective October 1, 2001. A utility may request a rate increase during the rate freeze period only when necessary to ensure the utility's financial viability. Under the Illinois legislation, if the earned return on common equity of a utility during this period exceeds an established threshold, one-half of the excess earnings must be refunded to customers. The threshold rate of return on common equity is based on the Monthly Treasury Bond Long-Term Average Rates (25 years and above) plus 8.5% in the years 2000 through 2006. Earnings for purposes of ComEd's threshold include ComEd's net income calculated in accordance with generally accepted accounting principles (GAAP) and reflect the amortization of regulatory assets. As a result of the Illinois legislation, at December 31, 2002, ComEd had a regulatory asset with an unamortized balance of $175 million that it expects to fully recover and amortize by the end of 2006. Consistent with the provisions of the Illinois legislation, regulatory assets may be recovered at amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold. The earned return on common equity and the threshold return on common equity for ComEd are each calculated on a two-year average basis. ComEd did not trigger the earnings sharing provision in 2002, 2001 or 2000 and does not currently expect to trigger the earnings sharing provisions in the years 2003 through 2006.

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        The Illinois legislation also provided for the collection of a CTC from customers who choose to purchase electric energy from an ARES or elect the PPO during a transition period that extends through 2006. The CTC, which was initially established as of October 1, 1999 and is applied on a cents per kWh basis, considers the revenue that would have been collected from a customer under tariffed rates, reduced by the revenue the utility will receive for providing delivery services to the customer, the market price for electricity and a defined mitigation factor, which represents the utility's opportunity to develop new revenue sources and achieve cost reductions. The CTC allows ComEd to recover some of its costs that might otherwise be unrecoverable under market-based rates.

        The rates for the generation service provided by ComEd under bundled rates are subject to a rate freeze during the transition period. ComEd has entered into a purchased power agreement (PPA) with Generation under which Generation has agreed to supply all of ComEd's load requirements through 2004. Prices for this energy vary depending upon the time of day and month of delivery. During 2005 and 2006, ComEd's PPA is a partial requirements agreement under which ComEd will purchase all of its required energy and capacity from Generation, up to the available capacity of the nuclear generating plants formerly owned by ComEd and transferred to Generation. Under the terms of the PPA, Generation is responsible for obtaining any required transmission service, subject to ComEd's obligation to obtain network service over the ComEd system. The PPA also specifies that prior to 2005, ComEd and Generation will jointly determine and agree on a market-based price for energy delivered under the PPA for 2005 and 2006. In the event that the parties cannot agree to market-based prices for 2005 and 2006 prior to July 1, 2004, ComEd has the option of terminating the PPA effective December 31, 2004. ComEd will obtain any additional supply required from market sources in 2005 and 2006, and subsequent to 2006, will obtain all of its supply from market sources, which could include Generation.

        As part of a settlement agreement between ComEd and the City of Chicago (Chicago) relating to ComEd's Chicago franchise agreement, ComEd and Chicago agreed to a revised combination of ongoing work under the franchise agreement and new initiatives that total approximately $1 billion in defined transmission and distribution expenditures by ComEd to improve electric service in Chicago, all of which has been expended through December 31, 2002. The Illinois legislation also committed ComEd to spend at least $2 billion during the period 1999 through 2004 on transmission and distribution facilities outside of Chicago, which had been expended as of December 31, 2001. In addition, ComEd conducted an extensive evaluation of the reliability of its transmission and distribution systems in response to certain high profile outages in the summer of 1999. As a result of the evaluation, ComEd has increased its capital and operating and maintenance expenditures on its transmission and distribution facilities in order to improve their reliability.

        As a result of ComEd's commitments to improve the reliability of its transmission and distribution system, ComEd expects its capital expenditures will exceed depreciation on its rate base assets through at least 2003. The base rate freeze will generally preclude incremental rate recovery of and on such incremental investments prior to January 1, 2007. Unless ComEd can offset the additional carrying costs against cost reductions, its return on investment will be reduced during the period of the rate freeze and until rate increases are approved authorizing a return of and on this new investment.

        In addition, the Illinois legislation provides that an electric utility, such as ComEd, will be liable for actual damages suffered by customers in the event of a continuous power outage of four hours or more affecting 30,000 or more customers and provides for reimbursement of governmental emergency and contingency expenses incurred in connection with any such outage. The legislation bars recovery of consequential damages. The legislation also allows an affected utility to seek relief from these provisions from the ICC where the utility can show that the cause of the outage was unpreventable damage due to weather events or conditions, customer tampering or third party causes.

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        The Illinois legislation also allows a portion of ComEd's future revenues to be segregated and used to support the issuance of securities by ComEd or a special purpose financing subsidiary. The proceeds, net of transaction costs, from such securities issuances must be used to refinance outstanding debt or equity or for certain other limited purposes. The total amount of such securities that may be issued is approximately $6.8 billion. In December 1998, special purpose financing subsidiaries of ComEd issued $3.4 billion of notes. For additional information, see ITEM 1. Business—Other Subsidiaries of ComEd and PECO with Publicly Held Securities and ITEM 8. Financial Statements and Supplementary Data—ComEd, Note 10 of Notes to Consolidated Financial Statements.

        ComEd is authorized to charge customers who purchase electricity from an alternative supplier for the use of its distribution system to deliver that electricity. These delivery service rates are set through proceedings before the ICC based upon, among other things, the operating costs associated with ComEd's distribution system and the capital investment that ComEd has made in its distribution system. On April 1, 2002, the ICC issued an interim order in a proceeding to establish ComEd's residential delivery services rates. The interim order was issued subject to an audit of the test year (the 2000 calendar year) expenditures, which has been completed. The purpose of the audit was to analyze and establish the reasonableness of past investments and expenditures, which ComEd believes it has shown. The rates became effective on May 1, 2002 when residential customers became eligible to choose their electricity supplier. Traditional bundled rates—rates paid by customers that retain ComEd as their electricity supplier—are not affected by this order. Delivery service rates for non-residential customers are not affected by this order.

        The firm hired by the ICC to audit the test year expenditures issued an audit report in October 2002 recommending additional disallowances to test year expenditures and rate base levels, which, if ultimately approved by the ICC, would result in lower residential delivery service charges and higher non-residential delivery service charges. ComEd intends to contest the audit findings in the reopened hearings and cannot currently determine what portion, if any, of the audit recommendations the ICC will accept. If the ICC ultimately determines that all or some portion of ComEd's distribution plan is not recoverable through rates, ComEd may be required to write-off some or all of the amount of its investment that the ICC determines is not recoverable. The estimated potential write-off, before income taxes, could be up to approximately $100 million if the audit recommendations were to be accepted by the ICC in their entirety. ComEd recorded a charge to earnings, before income taxes, of $12 million in the third quarter of 2002, representing the estimated minimum probable write-off exposure resulting from the audit findings. The ICC will hold hearings on the audit report and responses from ComEd and other parties. A final decision is expected in the middle of 2003.

        On July 19, 2002, ComEd filed a request with the ICC to revise the POLR obligation in Illinois. ComEd obtained permission from the ICC to limit the availability by June 2006 of Rate 6L for 370 of ComEd's largest energy customers with demands of at least three MWs, totaling approximately 2,500 MWs. Rate 6L is a bundled fixed rate offered to large customers including heavy industrial plants, large office buildings, government facilities and a variety of other businesses. On November 14, 2002, the ICC entered an interim order in response to ComEd's request to revise the POLR obligation it has in Illinois to be the back-up energy supplier to certain businesses. ComEd sought permission from the ICC to limit availability by June 2006 of a bundled fixed rate that it offers to large customers with energy demands of at least three megawatts, including heavy industrial plants, large office buildings, government facilities and a variety of other businesses. ComEd also sought approval of related tariff amendments to implement the request and for approval to make changes to its real-time pricing tariff, which would be made available to customers who choose not to go to the competitive market to procure their electric power and energy. The ICC interim order allowed the bundled fixed rate changes to take effect by operation of law, as allowed by statute, and directed that ComEd file tariffs that

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took effect on December 1, 2002, and will become operational on the first day of ComEd's June 2003 billing period. The order also directed ComEd to file proposed amendments to its real-time pricing tariff, which will be considered in a second phase of the proceeding. ComEd believes this phase of the proceeding will be concluded in a time frame that will coincide with the operational date of the bundled fixed rate changes. As of February 28, 2003, two parties had appealed the interim order.

        On March 3, 2003, ComEd entered into an agreement with various Illinois electric retail market suppliers, key customer groups and governmental parties regarding several matters affecting ComEd's rates for electric service (Agreement). The Agreement contemplates a series of coordinated filings with the ICC, which must issue orders consistent with the Agreement in order for the provisions of the Agreement to become effective.

        The Agreement addresses, among other things:

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ComEd's pending residential delivery services rate proceeding

New residential delivery service rates would be set based upon substantially the same rates currently in effect under the interim order and would remain in effect through December 31, 2006, with a possible reopener in the event that a reexamination in 2005 shows that ComEd is either under-recovering or over-recovering by more than 15% based on those rates. In addition, a $109 million distribution system capital expenditure disallowance that was proposed in the pending proceeding by a consulting firm engaged by the ICC to audit ComEd's test year expenditures, would not be reflected in the revenue requirement. Under the Agreement, distribution system plant reflected in the rate filing would be considered prudent and used and useful for purposes of this and future rate proceedings.

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Illinois electricity market development

There would be a modification of the methodology used to determine the market value energy credit. That credit is used to determine the price for specified market-based rate offerings by ComEd, and the rate for the CTC that ComEd is allowed to collect from customers who select an alternative retail electricity supplier. The credit would be adjusted upward through agreed upon "adders," which would take effect in June 2003 and would have the effect of reducing the CTC rate charged customers. The estimated annual revenue impact of the reduction in CTC revenues under the Agreement is approximately $65 million to $70 million. In addition, customers would be offered an option to lock-in CTC charges for longer periods. Currently, CTC charges are subject to change annually.

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Competitive service declarations that assist in mitigating ComEd's POLR obligations

The Agreement provides for the withdrawal of certain of the outstanding appeals of the competitive declaration for service to customers having load requirements of three or more megawatts. Also, it establishes a process for achieving in June 2004 a similar competitive declaration for service to customers having load requirements of one to three megawatts.

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ComEd's ability to enter into a full-requirements PPA with Generation

The parties to the Agreement would not contest extending ComEd's full requirements PPA, now in place through 2004, through 2006, replacing the partial requirements service for 2005 and 2006 in the existing agreement. The parties also would not contest ComEd's continued recovery of up to $73 million in nuclear decommissioning charges during 2005 and 2006, depending on the

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amount of energy that ComEd would purchase from Generation's nuclear plants formerly owned by ComEd.

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Funding of certain programs for customer and governmental groups

The Agreement provides for a total of $51 million in funding to various consumer groups and governmental agencies for a variety of programs from 2003 through 2006. Those programs may include energy and environmental programs, efficiency products and services, residential consumer education, market development studies and installation of emergency generating equipment.

        ComEd believes the Agreement assists in protecting the integrity of the CTC that it is allowed to collect from customers who choose an alternative supplier; sets a reasonable delivery service rate; provides customers and ComEd with greater price certainty and stability; enhances its relationship with regulatory, governmental and key customer groups; avoids the costs, uncertainty and time associated with litigation; and presents a proactive approach to increasing competition in the supply of electricity in Illinois.

        In order for the Agreement to become effective, the ICC, which is not a party to the Agreement, must enter orders consistent with the Agreement by late March 2003 in various regulatory proceedings that are the subject of the Agreement. Although the parties to the Agreement have agreed as to the general content of those orders, there are other parties to the proceedings who are seeking changes or modifications to the proposed orders or otherwise seeking to delay or prevent the effectiveness of the Agreement. As a result, there can be no assurance that the Agreement will become effective.

        If the Agreement becomes effective, ComEd would record a charge to earnings associated with the funding of specified programs and initiatives associated with the Agreement of $49 million on a present value basis before income taxes. This amount would be partially offset by the reversal of a $12 million (before income taxes) reserve established in the third quarter of 2002 for a potential capital disallowance in ComEd's delivery services rate proceeding, and a credit of $10 million (before income taxes) related to the capitalization of employee incentive payments provided for in the delivery services order. The net one-time charge for these items of $27 million (before income taxes) would be recognized upon receipt of necessary ICC approvals.

        PECO.    Under the Pennsylvania Electricity Generation Customer Choice and Competition Act (Competition Act), all of PECO's retail electric customers have the right to choose their generation suppliers. At December 31, 2002, approximately 21% of PECO's residential load, 10% of its small commercial and industrial load and 7% of its large commercial and industrial load were considered purchasing generation service from alternative generation suppliers. Customers who purchase energy from an electric generation supplier (EGS) continue to pay a delivery charge.

        In addition to retail competition for generation services, PECO's settlement of its restructuring case mandated by the Competition Act established caps on generation and distribution rates. The 1998 settlement also authorized PECO to recover $5.3 billion of stranded costs and to securitize up to $4.0 billion of its stranded cost recovery.

        Under the 1998 settlement, PECO's distribution rates were capped through June 30, 2005 at the level in effect on December 31, 1996. Generation rates, consisting of the charge for stranded cost recovery and a shopping credit or capacity and energy charge, were capped through December 31, 2010. For 2003, the generation rate cap is $0.0698 per kWh, increasing to $0.0751 per kWh in 2006 and $0.0801 per kWh in 2007. The rate caps are subject to limited exceptions, including significant increases

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in Federal or state taxes or other significant changes in law or regulations that would not allow PECO to earn a fair rate of return.

        Pursuant to a settlement related to PECO's request for authorization to securitize an additional $1 billion of its stranded cost recovery, PECO provided its customers with additional rate reductions of $60 million in 2001. Under the settlement agreement entered into by PECO in 2000 relating to the PUC's approval of the Merger, PECO agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through 2005 and extended the rate cap on distribution rates through December 31, 2006.

        As a mechanism for utilities to recover their allowed stranded costs, the Competition Act provides for the imposition and collection of non-bypassable transition charges on customers' bills. Transition charges are assessed to and collected from all retail customers who have been assigned stranded cost responsibility and access the utility's transmission and distribution systems. As the transition charges are based on access to the utility's transmission and distribution system, they are assessed regardless of whether such customer purchases electricity from the utility or an alternative electric generation supplier. The Competition Act provides, however, that the utility's right to collect transition charges is contingent on the continued operation at reasonable availability levels of the assets for which the stranded costs were awarded, except where continued operation is no longer cost efficient because of the transition to a competitive market. To the extent the actual recoveries of transition charges in any one year differ from the authorized amount set forth below, an annual reconciliation adjustment to the transition charges rate is made to increase or decrease the subsequent year's collections accordingly, except during 2010 in which the reconciliation adjustments are made quarterly or monthly as needed.

        PECO has been authorized to recover stranded costs of $5.3 billion over a twelve-year period ending December 31, 2010 with a return on the unamortized balance of 10.75%. The following table shows PECO's allowed recovery of stranded costs, and amortization of the associated regulatory asset, for the years 2003 through 2010 as authorized by the PUC based on the level of transition charges established in the settlement of PECO's restructuring case. Recovery of transition charges for stranded costs and PECO's allowed return on its recovery of stranded costs are included in operating revenue.

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PECO Annual Stranded Cost
Amortization And Return per the Electric Restructuring Settlement

        Under the Competition Act, licensed entities, including alternative electric generation suppliers, may act as agents to provide a single bill and provide associated billing and collection services to retail customers located in PECO's retail electric service territory. In that event, the alternative supplier or other third party replaces the customer as the obligor with respect to the customer's bill and PECO generally has no right to collect such receivable from the customer. Third-party billing would change PECO's customer profile (and risk of non-payment by customers) by replacing multiple customers with the entity providing third-party billing for those customers. PUC-licensed entities may also finance, install, own, maintain, calibrate and remotely read advanced meters for service to retail customers in PECO's retail electric service territory. To date, no third parties are providing billing of PECO's charges to customers or advanced metering. Only PECO can physically disconnect or reconnect a customer's distribution service.

        The PUC's Final Electric Restructuring Order provided for the phase-in of customer choice of EGS and as of January 1, 2000, all customers were eligible for customer choice. The Final Restructuring Order also established market share thresholds (MST) to promote competition. The MST requirements provided that, if as of January 1, 2001 and January 1, 2003, respectively, less than 35% and 50% of residential and commercial customers were shopping, the number of customers sufficient to meet the MST would be randomly selected and assigned to an EGS through a PUC-determined process. For residential and small commercial customers, the threshold measurement is by number of customers. For large commercial customers the measurement is by load. On January 1, 2001, the 35% MST threshold was met for all customer classes as a result of agreements assigning customers to New Power Company (New Power) and Green Mountain Energy Company (Green Mountain) as providers of last resort default service. During 2002, PECO experienced an increase in the number of customers selecting or returning to PECO as their EGS. At January 1, 2003, PECO did not meet the MST requirement. In January 2003, PECO submitted to the PUC an MST plan to meet the 50% threshold requirement for its small and large commercial customer classes, which was approved on February 6, 2003. According to the approved plan, randomly assigned customers who participated will be switched to winning MST bidders as of their respective meter read dates. On February 24, 2003, the small and large commercial MST auction was completed. There were three winning bidders who were awarded a total of 64,172 small commercial customers, at a clearing price of 1.25% off PECO's tariffed rate GS. No bids were received for the small commercial renewable auction or the large commercial (GS6) non-interval metered load auction. Also in February 2003, PECO filed an MST plan for the residential customer classes, which is pending PUC approval.

        On November 29, 2000, the PUC approved PECO's bilateral contract with New Power to move 22% of PECO's non-shopping residential customers to New Power for competitive default generation

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service (CDS). Under this contract, New Power agreed to provide generation services through January 2004, at specified discounted rates, to nearly 300,000 residential customers of PECO who were taking their generation service from PECO. On February 22, 2002, New Power notified PECO of its intent to withdraw from providing CDS to approximately 180,000 residential customers. As a result of that withdrawal, those CDS customers were returned to PECO in the second quarter of 2002. Pursuant to a tariff filing approved by the PUC, PECO is serving those returned customers at the discount generation rates provided for under the original New Power CDS Agreement for the remaining term of that contract. Subsequently, in the second quarter of 2002, New Power also advised PECO it planned to withdraw from serving all of its customers in Pennsylvania, including approximately 15,000 non-CDS PECO customers. These customers were returned to PECO during the third quarter of 2002.

        In addition to the New Power contract, PECO also entered into a CDS agreement with Green Mountain to assign 50,000 of PECO's non-shopping residential customers to Green Mountain on the same terms and conditions as the New Power contract. On February 21, 2001, the PUC approved the Green Mountain CDS agreement. Beginning in May 2001, Green Mountain enrolled approximately 44,000 customers and as of December 31, 2002, approximately 18,000 customers, or 37%, have opted to return to PECO.

        PECO has entered into a PPA with Generation under which PECO obtains substantially all of its electric supply from Generation through 2010. Also, under the 2001 corporate restructuring, PECO assigned its rights and obligations under various PPAs and fuel supply agreements to Generation. Generation supplies power to PECO from the transferred generation assets, assigned PPAs and other market sources.

        As permitted by the Pennsylvania Electric Act, the Pennsylvania Department of Revenue has calculated a 2002 Revenue Neutral Reconciliation (RNR) adjustment to gross receipts tax rate in order to neutralize the impact of electric restructuring on its tax revenues. In January 2002, the PUC approved the RNR adjustment to the gross receipts tax rate collected from customers. Effective January 1, 2002, PECO implemented the change in the gross receipts tax rate. The RNR adjustment increases the gross receipts tax rate, which increased both PECO's annual revenues and tax obligations by approximately $50 million in 2002. The RNR adjustment was under appeal. The case was remanded to the PUC and in August 2002, the PUC ruled that PECO is properly authorized to recover these costs. In December 2002, the PUC approved the inclusion of the RNR factor in PECO's base rates eliminating the need for an annual filing to obtain approval for recovery.

Transmission Services

        Energy Delivery provides wholesale and unbundled retail transmission service under rates established by FERC. FERC has used its regulation of transmission to encourage competition for wholesale generation services and the development of regional structures to facilitate regional wholesale markets. In December 1999, FERC issued Order No. 2000 (Order 2000) requiring jurisdictional utilities to file a proposal to form a regional transmission organization (RTO) or, alternatively, to describe efforts to participate in or work toward participating in an RTO or explain why they were not participating in an RTO. Order 2000 is generally designed to separate the governance and operation of the transmission system from generation companies and other market participants.

        PJM Interconnection, LLC (PJM) is the independent system operator and the FERC approved RTO for the Mid-Atlantic region in which it operates. PJM is the transmission provider under, and the administrator of, the PJM Open Access Transmission Tariff (PJM Tariff), operates the PJM Interchange Energy Market and Capacity Credit Markets, and conducts the day-to-day operations of the bulk power system of the PJM region. PECO's transmission system is currently under the control of PJM, and ComEd has taken steps to place its transmission system under PJM's control. Under the PJM tariff,

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transmission service is provided on a region-wide, open-access basis using the transmission facilities of the PJM members at rates based on the costs of transmission service.

        ComEd.    On May 28, 2002, ComEd filed a notice with FERC indicating its intention to comply with Order 2000 by placing its transmission assets under the control of an independent transmission company (ITC) that would operate under a western expansion of PJM. ComEd committed to join PJM independently if no ITC was formed.

        FERC conditionally approved ComEd's decision to join PJM in late July 2002. Among other conditions, FERC ordered the applicable parties to file agreements relating to the formation of the ITC under PJM. ComEd, American Electric Power East (AEP), Dayton Power & Light (Dayton) and National Grid USA (National Grid) subsequently filed a non-binding letter of intent and detailed term sheet relating to the formation of the ITC. National Grid is a subsidiary of National Grid plc, a company that owns and operates transmission assets in Great Britain. National Grid and PJM have engaged in negotiations with respect to the allocation of functions to an ITC operating under PJM and certain cost recovery issues. They did not reach complete agreement, and PJM filed its proposed resolution of certain of these issues with FERC. On March 14, 2003, FERC issued an order that approved PJM's proposal with certain modifications. As a result, it is unlikely that ComEd will participate in an ITC when it joins PJM.

        Effective as of September 30, 2002, ComEd, AEP, Dayton and National Grid entered into a Project Implementation Agreement with PJM providing for the funding and allocation of responsibilities with respect to the integration of the parties into PJM West, either directly or through an ITC. This Agreement provides for the companies to reimburse PJM for implementation costs that PJM would not capitalize under its ordinary accounting principles. The companies would recover these amounts in their transmission rates pursuant to the PJM tariff amendments described in the next paragraph. ComEd faces significant additional costs under this Agreement if it ultimately does not join PJM.

        On December 11, 2002, ComEd, AEP, Dayton, Dominion Virginia Power (Dominion) and PJM filed with FERC amendments to PJM's transmission tariff (including proposed transmission rates) and certain PJM agreements to be entered into by the parties. These amendments are necessary to integrate ComEd and these other utilities into PJM. Subject to FERC approval of such amendments, ComEd expects to transfer functional control of its transmission assets to PJM and to integrate fully into PJM's energy market structures during 2003.

        On December 19, 2002, FERC issued an order granting PJM full RTO status, based in part upon PJM's proposed expansion to include AEP, ComEd, Dayton and Dominion. FERC had previously granted PJM only provisional RTO status, voicing concerns about its scope and configuration. Prior to joining PJM, ComEd must receive final approval from FERC.

        The State of Virginia is expected to enact a law in the first quarter of 2003 prohibiting utilities operating in the State of Virginia, including AEP and Dominion, from joining an RTO prior to July 1, 2004, and conditioning entry into an RTO on approval of the Virginia utility commission. Enactment of this law may delay AEP and Dominion's entry into PJM. ComEd is working with PJM to develop an implementation plan to facilitate ComEd's entry into PJM without AEP. Exelon is also evaluating the possible impact any such delay may have on ComEd and its participation in PJM, as well as on Exelon itself.

        PECO.    PECO provides regional transmission service pursuant to PJM's regional open-access transmission tariff. PECO and the other transmission owners in PJM have turned over control of their transmission facilities to PJM.

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Gas

        PECO's gas sales and gas transportation revenues are derived pursuant to rates regulated by the PUC. Customers have the right to choose their gas suppliers or purchase their gas supply from PECO at cost.

        The PUC established, through regulated proceedings, the base rates that PECO may charge for gas service in Pennsylvania. PECO's gas rates are subject to quarterly adjustments designed to recover or refund the difference between the actual cost of purchased gas and the amount included in base rates and to recover or refund increases or decreases in certain state taxes not recovered in base rates.

        Approximately one-third of PECO's current total yearly throughput is supplied by third parties. The transportation service provided remains subject to rate regulation. PECO also provides billing, metering, installation, maintenance and emergency response services.

        PECO's natural gas supply is provided by purchases from a number of suppliers for terms of up to five years. These purchases are delivered under several long-term firm transportation contracts. PECO's aggregate annual firm supply under these firm transportation contracts is 47.5 million dekatherms. Peak gas is provided by PECO's liquefied natural gas (LNG) facility and propane-air plant. PECO also has under contract 21.3 million dekatherms of underground storage through service agreements. Natural gas from underground storage represents approximately 34% of PECO's 2002-2003 heating season planned supplies.

Construction Budget

        Energy Delivery's business is capital intensive and requires significant investments in energy transmission and distribution facilities, and in other internal infrastructure projects. The following table shows Exelon's most recent estimate of capital expenditures for plant additions and improvements for ComEd and PECO for 2003:

        Approximately two-thirds of ComEd's 2003 budgeted capital expenditures and one-half of PECO's 2003 budgeted capital expenditures are for additions to or upgrades of existing facilities, including reliability improvements. The remainder of the capital expenditures support customer and load growth.

Generation

General

        Generation is one of the largest competitive electric generation companies in the United States, as measured by owned and controlled MWs. Generation combines its large, low-cost generation fleet with an experienced wholesale power marketing operation. At December 31, 2002, Generation directly owned generation assets in the Northeast, Mid-Atlantic, Midwest and Texas regions with a net capacity of 26,762 MWs, including 14,547 MWs of nuclear capacity, 9,794 MWs of fossil fuel capacity, and 2,421 MWs of capacity under construction. Generation also controls another 13,900 MWs of capacity in the Midwest, Southeast and South Central regions through long-term contracts.

        In addition to its owned generation facilities, Generation owns a 50% interest in AmerGen, a joint venture with British Energy, Inc., a wholly-owned subsidiary of British Energy plc (British Energy).

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AmerGen owns three nuclear stations with total generation capacity of 2,481 MWs. Generation also owns a 49.9% interest in Sithe and is subject to a Put and Call Agreement (PCA) that gives Generation the right to purchase (Call) the remaining 50.1% of Sithe, and gives the other Sithe shareholders the right to sell (Put) their interest to Generation. See the Unconsolidated Equity Investments section in ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Generation for a further discussion of the PCA. Sithe owns and operates 19 generating stations in North America. Currently, Sithe has a total generating capacity of 1,321 MWs in operation and 230 MWs under construction.

        Generation's wholesale marketing unit, Power Team, is a major wholesale marketer of energy that uses Generation's energy generation portfolio, transmission rights and expertise to ensure delivery of energy to Generation's wholesale customers under long-term and short-term contracts. Power Team is responsible for supplying the load requirements of ComEd and PECO and markets the remaining energy in the wholesale and spot markets.

Generating Resources

        The generating resources of Generation, including its ownership share of AmerGen and Sithe, consist of the following:

(1)

See ITEM 1. Business—Generation "Fuel" for sources of fuels used in electric generation.

(2)

Based on Generation's percentage ownership.

(3)

Contracts range from 1 to 29 years.

        The owned generating resources of Generation are located primarily in the Midwest (approximately 53% of capacity), the Mid Atlantic and New England regions (approximately 36% of capacity), and the Texas region (approximately 11%). AmerGen's generating resources are in the Midwest and the Mid Atlantic regions. Sithe's generating resources are primarily in New York. The remaining plants are located throughout North America.

        On April 25, 2002, Generation acquired two natural gas and oil-fired plants from TXU Corp. (TXU). The purchase included the 893-MW Mountain Creek Steam Electric Station in Dallas and the 1,441-MW Handley Steam Electric Station in Fort Worth. The transaction included a PPA for TXU to purchase power during the months of May through September from 2002 through 2006. During the periods covered by the PPA, TXU makes fixed capacity payments, variable expense payments, and provides fuel to Exelon in return for exclusive rights to the energy and capacity of the generation plants.

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        On November 1, 2002, Generation purchased the assets of Sithe New England Holdings, LLC (Sithe New England), a subsidiary of Sithe, and related power marketing operations. Sithe New England's primary assets are gas-fired facilities currently under construction. Sithe New England owns 4,066 MWs of generation capacity, consisting of 1,645 MWs in operation and 2,421 MWs under construction. Sithe New England's generation facilities are located primarily in Massachusetts.

        For a further discussion of Sithe and the Sithe New England asset acquisition, see "Sithe" section, which follows within ITEM 1. Business—Generation.

        The generation assets transferred to Generation by ComEd and PECO during the 2001 corporate restructuring, the generating plants acquired in 2002 and Generation's investments in Sithe and AmerGen provide a critical mass of generation capacity and a leadership position in the wholesale energy markets. As the largest generator of nuclear power in the United States, Generation can take advantage of its scale and scope to negotiate favorable terms for the materials and services that its business requires.

        Nuclear Facilities.    Generation has direct ownership interests in eight nuclear generating stations, consisting of 16 units with 14,547 MW of capacity (Exelon's share). For additional information, see ITEM 2. Properties. All of the nuclear generating stations are operated by Generation, with the exception of Salem Generating Station (Salem), which is operated by PSE&G Nuclear, LLC. In addition, AmerGen owns three nuclear generating stations consisting of three units with 2,481 MWs of capacity, of which Generation's interest is 1,241 MWs. See the AmerGen section, which follows within ITEM 1. Business—Generation, for further discussion of the three nuclear facilities owned by AmerGen.

        In 2002, over 50% of Generation's electric supply was generated from the nuclear generating facilities. During 2002 and 2001, the nuclear generating facilities operated by Generation, operated at weighted average capacity factors of 92.7% and 94.4%, respectively. See the AmerGen section, which follows within ITEM 1. Business—Generation, for a further discussion of the three nuclear facilities owned by AmerGen.

        Licenses.    Exelon has 40-year operating licenses from the NRC for each of its nuclear units. Generation applied to the NRC in July 2001 for renewal of the Peach Bottom units 2 and 3 licenses and has applied for the extension of the operating license for Dresden units 2 and 3 and Quad Cities Station in January 2003. The operating license renewal process takes approximately four to five years from the commencement of the project at a site 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 expiration. Depreciation provisions are based on the estimated useful lives of the units, which assume the extension of these

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licenses for all of the nuclear generating stations. The following table summarizes the current operating license expiration dates for Generation's nuclear facilities in service.

        Regulation of Nuclear Power Generation and Security.    Generation is subject to the jurisdiction of the NRC with respect to its nuclear generating stations, including the licensing of operation of each station. The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security, environmental and radiological aspects of those stations. The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of such licenses. Changes in regulations by the NRC may require a substantial increase in capital expenditures for nuclear generating facilities or increased operating costs of nuclear generating units.

        The NRC oversight process uses objective, timely and safety-significant criteria in assessing performance. It also takes into account improvements in the performance of the nuclear industry over the past twenty years. Nuclear plant performance is measured by a combination of 18 objective performance indicators and by the NRC inspection program. These are closely focused on those plant activities having the greatest impact on safety and overall risk. In addition, the NRC conducts periodic reviews of the effectiveness of each operator's programs to identify and correct problems. The inspection program is designed to verify the accuracy of performance indicator information and to assess performance based on safety cornerstones. These include initiating events, mitigating systems, integrity of barriers to release of radioactivity, emergency preparedness, occupational and public radiation safety, and physical protection.

        The NRC evaluates licensee performance by analyzing two distinct inputs: inspection findings resulting from the NRC inspection program and performance indicators reported by the licensees on a quarterly basis.

        NRC reactor oversight results for the fourth quarter of 2002 indicate that the performance indicators for the Exelon nuclear plants are all in the highest performance band, with the exception of one indicator for Dresden Unit 3, which is still considered to be acceptable performance within that indicator by the NRC.

        Exelon does not fully know the impact that future terrorist attacks or threats of terrorism may have on its industry in general and on Exelon in particular. The events of September 11, 2001 have

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affected Exelon's operating procedures and costs. Exelon has initiated security measures to safeguard its employees and critical operations and is actively participating in industry initiatives to identify methods to maintain the reliability of Exelon's energy production and delivery systems. Generation has met or exceeded all security measures mandated by the NRC for nuclear plants after the September 11, 2001 terrorist attacks. These security measures resulted in increased costs in 2002 of $19 million, of which approximately $10 million was capitalized. On a continuing basis, Exelon is evaluating enhanced security measures at certain critical locations, enhanced response and recovery plans and assessing long-term design changes and redundancy measures. Additionally, the energy industry is working with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country's energy systems. These measures will involve additional expense to develop and implement, but will provide increased assurances as to Exelon's ability to continue to operate under difficult times.

        Nuclear Waste Disposal.    There are no facilities for the reprocessing or permanent disposal of spent nuclear fuel (SNF) currently in operation in the United States, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by nuclear generation facilities in on-site storage pools and, in the case of Peach Bottom and Dresden, some SNF has been placed in dry cask storage facilities. Not all of Generation's SNF storage pools have sufficient storage capacity for the life of the plant. Generation is developing dry cask storage facilities, as necessary to support operations.

        Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy (DOE) is responsible for the selection and development of repositories for, and the disposal of, SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contract) to provide for disposal of SNF from its nuclear generating stations. In accordance with the NWPA and the Standard Contract, Generation pays the DOE one mill ($.001) per kWh of net nuclear generation for the cost of nuclear fuel long-term storage and disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contract required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance will be delayed significantly. The DOE's current estimate for opening a SNF permanent disposal facility is 2010. This extended delay in SNF acceptance by the DOE has led to Generation's adoption of dry storage at its Dresden, Quad Cities and Peach Bottom Stations and its consideration of dry storage at other stations.

        In July 1998, ComEd filed a complaint against the United States Government (Government) in the United States Court of Federal Claims (Court) seeking to recover damages caused by the DOE's failure to honor its contractual obligation to begin disposing of SNF in January 1998. This litigation was assumed by Generation in the 2001 corporate restructuring. In August 2001, the Court granted Generation's motion for partial summary judgment for liability on ComEd's breach of contract claim. In November 2001, the Government filed two partial summary judgment motions relating to certain damage issues in the case, as well as two motions to dismiss claims other than the breach of contract claim. On August 30, 2002, after taking discovery related to certain damages, Generation filed briefs in response to the DOE's motions. The Court has postponed the time for the DOE to file reply briefs while it entertains additional DOE discovery motions.

        In July 2000, PECO entered into an agreement with the DOE relating to Generation's Peach Bottom nuclear generating unit to address the DOE's failure to begin removal of SNF in January 1998 as required by the Standard Contract (Amendment). Under that agreement, the DOE agreed to provide PECO with credits against PECO's future contributions to the Nuclear Waste Fund over the next ten years to compensate PECO for SNF storage costs incurred as a result of the DOE's breach of the Standard Contract. The agreement also provides that, upon PECO's request, the DOE will take title to the SNF and the interim storage facility at Peach Bottom, provided certain conditions are met. Generation assumed this contract in 2001 corporate restructuring.

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        In November 2000, eight utilities with nuclear power plants filed a Joint Petition for Review against the DOE with the United States Court of Appeals for the Eleventh Circuit seeking to invalidate that portion of the agreement providing for credits to PECO against nuclear waste fund payments on the ground that such provision is a violation of the NWPA. PECO intervened as a defendant in that case, and Generation assumed the claim in the 2001 corporate restructuring. On September 24, 2002, the United States Court of Appeals for the Eleventh Circuit ruled that the fee adjustment provision of the agreement violates the NWPA and therefore is null and void. The Court did not hold that the agreement as a whole is invalid. The Amendment provides that if any portion of the Amendment is found to be void, the DOE and Generation agree to negotiate in good faith and attempt to reach an enforceable agreement consistent with the spirit and purpose of the Amendment. That provision further provides that should a major term be declared void, and the DOE and Generation cannot reach a subsequent agreement, the entire Amendment would be rendered null and void, the original Peach Bottom Standard Contract would remain in effect and the parties would return to pre-Amendment status. Generation has begun negotiations with the DOE and those negotiations are ongoing. Under the agreement, Generation has received approximately $40 million in credits against contributions to the nuclear waste fund.

        In April 2001, an individual filed suit against the DOE with the United States District Court for the Middle District of Pennsylvania seeking to invalidate the agreement on the grounds that the DOE has violated the National Environmental Policy Act and the Administrative Procedure Act. PECO intervened as a defendant and moved to dismiss the complaint. Generation assumed the defense in 2001 corporate restructuring. On September 30, 2002, the Court granted Generation's motion and dismissed the lawsuit on the ground that the Court did not have jurisdiction over the matter.

        The Standard Contract with the DOE also requires that PECO and ComEd pay the DOE a one-time fee applicable to nuclear generation through April 6, 1983. PECO's fee has been paid. Pursuant to the Standard Contract, ComEd elected to pay the one-time fee of $277 million, with interest to the date of payment, just prior to the first delivery of SNF to the DOE. As of December 31, 2002, the unfunded liability for the one-time fee with interest was $858 million. The liabilities for spent nuclear fuel disposal costs, including the one-time fee, were transferred to Generation as part of the 2001 corporate restructuring.

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

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

        The National Energy Policy Act of 1992 requires that the owners of nuclear reactors pay for the decommissioning and decontamination of the DOE uranium enrichment facilities. The total cost to all domestic utilities covered by this requirement was originally $150 million per year through 2006, of which Generation's share was approximately $20 million per year. Payments are adjusted annually to reflect inflation. Including the effect of inflation, Generation paid $25 million in 2002.

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        Insurance.    The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. As of January 1, 2003, the current limit is $9.5 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. Generation carries the maximum available commercial insurance of $300 million and the remaining $9.2 billion is provided through mandatory participation in a financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed up to $89 million per reactor per incident, payable at no more than $10 million per reactor per incident per year. This assessment is subject to inflation and state premium taxes. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims. The Price-Anderson Act expired on August 1, 2002 but existing facilities, including those owned and operated by Generation, remain covered. The Price-Anderson Act provisions relating to commercial facilities were extended through 2003. The extension affects facilities obtaining NRC operating licenses in 2003. Existing facilities are unaffected by the extension.

        Generation carries property damage, decontamination and premature decommissioning insurance for each station loss resulting from damage to its nuclear plants. In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. Under the terms of the various insurance agreements, Generation could be assessed up to $124 million for losses incurred at any plant insured by the insurance companies. In the event that one or more acts of terrorism cause accidental property damage within a twelve month period from the first accidental property damage under one or more policies for all insureds, the maximum recovery for all losses by all insureds will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity, and any other source, applicable to such losses. The $3.2 billion maximum recovery limit is not applicable, however, in the event of a "certified act of terrorism" as defined in the Terrorism Risk Insurance Act of 2002, as a result of government indemnity. Generally, a "certified act of terrorism" is defined in the Terrorism Risk Insurance Act to be any act, certified by the U.S. government, to be an act of terrorism committed on behalf of a foreign person or interest.

        Additionally, Generation is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), that provides replacement power cost insurance in the event of a major accidental outage at a nuclear station. The premium for this coverage is subject to assessment for adverse loss experience. Generation's maximum share of any assessment is $46 million per year. Recovery under this insurance for terrorist acts is subject to the $3.2 billion aggregate limit and secondary to the property insurance described above. This limit would also not apply in cases of certified acts of terrorism under the Terrorism Risk Insurance Act as described above.

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

        Generation does not carry any business interruption insurance for nuclear operations other than the NEIL coverage. Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained. Such losses could have a material adverse effect on Generation's financial condition and results of operations.

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        Decommissioning.    NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. Based on estimates of decommissioning costs for each of the nuclear facilities in which Generation has an ownership interest, the ICC permits ComEd, and the PUC permits PECO to collect from its customers and deposit in nuclear decommissioning trust funds maintained by Generation amounts which, together with earnings thereon, will be used to decommission such nuclear facilities. As of December 31, 2002, Generation's estimate of its nuclear facilities' decommissioning cost is $7.4 billion in current year (2003) dollars. The liability for decommissioning each generation station is recognized ratably over that generating station's service life. At December 31, 2002, the decommissioning liability recorded in accumulated depreciation and deferred credits and other liabilities was $2.8 billion and $1.4 billion, respectively. Decommissioning expenditures are expected to occur primarily after the plants are retired and are currently estimated to begin in 2029 for plants currently in operation. Decommissioning costs are currently recoverable by ComEd and PECO through regulated rates and are remitted to Generation for deposit in the decommissioning trust funds. In 2002, ComEd and PECO remitted to Generation approximately $102 million in decommissioning collections. Generation believes that the amounts being remitted to it by ComEd and PECO and the earnings on nuclear decommissioning trust funds will be sufficient to fully fund Generation's decommissioning obligations. See The Critical Accounting Estimates and New Accounting Pronouncements section within ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Generation for a further discussion of Nuclear Decommissioning.

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

        Nuclear decommissioning costs associated with the nuclear generating stations formerly owned by PECO continue to be recovered currently through rates charged by PECO to regulated customers. These amounts are remitted to Generation as allowed by the PUC. Under an agreement effective September 2001, PECO remits $29 million per year to Generation related to nuclear decommissioning cost recovery.

        On December 31, 2002, PECO filed with the PUC for an annual increase in its decommissioning cost recovery of $20 million effective June 1, 2004. The filing is consistent with provisions in the 1998 settlement and the settlement agreement entered into by PECO in 2000 related to the PUC's approval of the Merger, which require PECO to update the cost of decommissioning every five years. The additional amount requested is expected to be reduced as it does not reflect pending life extensions at Peach Bottom. The approval of the life extensions is expected by mid-2003.

        Zion, a two-unit nuclear generation station, and Dresden Unit 1 formerly owned by ComEd, have permanently ceased power generation. ComEd transferred Zion and Dresden Unit 1, as well as their related decommissioning liabilities and trust funds, to Generation as part of the 2001 corporate restructuring. Zion and Dresden Unit 1's SNF is currently being stored in on-site storage pools and dry cask storage, respectively, until a permanent repository under the NWPA is completed. Generation has

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recorded a liability of $1.4 billion, which represents the estimated cost of decommissioning Zion and Dresden Unit 1 in current year dollars. Decommissioning expenditures are expected to occur primarily after 2013 and 2030 for Zion and Dresden Unit 1, respectively.

Fossil and Hydroelectric Facilities.

        Fossil units include:

•

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



•

intermediate units—the Cromby, Eddystone, and Mystic units that have dual fuel (oil/gas) capability; Handley, Mountain Creek and New Boston are gas fueled stations, Wyman is an oil fueled station; and



•

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

        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.

        Generation operates all of its fossil and hydroelectric facilities other than La Porte, Keystone, Conemaugh and Wyman. In 2002, approximately 6% of Generation's electric output was generated from Generation's owned fossil and hydroelectric generation facilities. The majority of this output was dispatched to support Generation's power marketing activities.

        Generation is in the process of improving the operating performance and efficiency of its units. Recent activities include the following:

•

a new eight unit 350-MW gas facility was brought on-line in July 2002 in the Mid-West region,



•

control system upgrades at the Conowingo and Muddy Run hydro facilities to improve plant efficiency, and



•

completion of a major turbine overhaul at the Cromby coal unit and further turbine overhauls are being studied for economic feasibility.

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

        Additionally, Generation anticipates the construction of the new generating facilities in the New England region (Mystic 8&9 and Fore River) will be completed in the 2^nd quarter of 2003. They are state of the art combined gas turbine stations. The Fore River station has dual fuel (oil/gas) capability. The plants will increase capacity by 2,421 MWs.

        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. Generation is 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.

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        Insurance.    Generation does not carry business interruption insurance for its fossil and hydroelectric operations other than its coverage for Sithe New England. Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained. Such losses could have a material adverse effect on Generation's financial condition and results of operations.

Long-Term Contracts

        In addition to owned generation assets, Generation sells electricity purchased under the long-term contracts described below:

        Midwest Generation, LLC Contract.    Generation is a party to contracts with Midwest Generation, LLC (Midwest Generation), a subsidiary of Edison Mission Energy. Under the contracts, Generation 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, Generation pays 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, Generation has annual rights to reduce the capacity and related energy purchase obligations, and some of these rights were recently exercised. On January 1, 2002, Generation released all of the 355 MW of oil-fixed peaking capacity that is covered by the contracts. On July 1, 2002, Generation elected to exercise its call option on 1,265 MWs of capacity for 2003. Generation has a total of 4,879 MWs of capacity under the Coal, Collins Generating Station (Collins) and Peaking Unit (Peaking) PPAs, of which Generation retains 1,918 MWs of option capacity under the Collins and Peaking PPAs as well as 1,265 MWs of option capacity under the Coal Generation PPA. Generation will decide whether to exercise its options in 2003, effective January 1, 2004, depending on the projected need for capacity and energy to fulfill obligations under the agreement with ComEd or otherwise, taking into account forward market conditions and other alternatives. On October 2, 2002, Generation notified Midwest Generation of its exercise of termination options under the existing Collins and Peaking Unit (Peaking) PPAs. Generation exercised its termination options on 1,727 MWs in 2003 and 2004. In 2003, Generation will take 1,778 MWs of option capacity under the Collins and Peaking Unit Agreements as well as 1,265 MWs of option capacity under the Coal Generation PPA.

Federal Power Act

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

        Because Generation sells power in the wholesale markets, Generation is deemed to be a public utility for purposes of the Federal Power Act and is required to obtain FERC's acceptance of the rate schedules for wholesale sales of electricity. Generation has received authorization from FERC to sell

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energy at market-based rates. As is customary with market-based rate schedules, FERC reserved the right to suspend market-based rate authority on a retroactive basis if it is subsequently determined that Generation or any of its affiliates exercised or have the ability to exercise market power. FERC is also authorized to order refunds if it finds that market-based rates are unreasonable.

        In April 1996, FERC issued Order No. 888 (Order 888). The intent of Order 888 was to open the transmission grid subject to FERC's jurisdiction to all eligible customers, including sellers of power and retail customers, in states where retail access is approved. Order 888 requires that owners of transmission facilities provide access to their transmission facilities under filed tariffs at cost-based rates. In connection with Order 888, FERC issued Order No. 889 (Order 889). Under Order 889, PECO and ComEd were required to file Standards of Conduct, which governed the communication of non-public information between transmission personnel and employees of any affiliated wholesale merchant function. FERC recently issued a Notice of Proposed Rulemaking for the Standards of Conduct for Transmission Providers. Among other things, FERC is considering whether it would be appropriate for it to adopt measures that would limit the amount of capacity an affiliate can hold in a transmission provider. Generation's business would be impacted if any of these measures were instituted.

        As described above under Energy Delivery—Transmission Services, in December 1999, FERC issued Order 2000, to encourage the voluntary formation of RTOs by December 2001 that would provide transmission service across multiple transmission systems. One of the intended benefits of establishing these entities is to eliminate or reduce transmission charges imposed by successive transmission systems when wholesale generators cross several transmission systems to deliver capacity. However, inconsistencies in the pace of RTO development and significant state public utility commission concerns caused FERC to indefinitely extend its operational target date of December 2001. PJM has been approved as an RTO, as has the Midwest ISO. However, ISOs operating in other regions where Generation owns facilities have not yet been fully approved as RTOs.

        FERC has also proposed rulemakings to mandate a standard market design (SMD) for the wholesale markets. Order 2000 and the proposed SMD rule contemplate that the jurisdictional transmission owners in a region will turn over operating authority over their transmission facilities to an RTO or other independent entity for the purpose of providing open transmission access. As a result, the independent entity will become the provider of the transmission service and the transmission owners will recover their revenue requirements through the independent entity. The transmission owners will remain responsible for maintaining and physically operating their transmission facilities. The SMD rulemaking proposal would also require RTOs to operate an organized bid-based wholesale market for those who wish to sell their generation through the market and to implement a financially-based system for dealing with congestion on transmission lines known as "locational marginal pricing" (LMP). FERC has also issued proposals to encourage RTO development, independent control of the transmission grid and expansion of the transmission grid by providing enhanced returns on equity for transmission assets. FERC's SMD proposal has met with substantial opposition from a number of parties, including some state regulators and other governmental officials. As a result, FERC has delayed issuance of a final rule indefinitely while it seeks further comment.

        FERC Order 2000 has not led to the rapid development of RTOs and FERC has not yet finalized its SMD proposal, due in part to the resistance noted above. Exelon supports both of these proposals but cannot predict whether they will be successful, what impact they may ultimately have on Exelon's transmission rates, revenues and operation of its transmission facilities, or whether they will ultimately lead to the development of large, successful regional wholesale markets. To the extent ComEd and PECO have POLR obligations, and may at some point no longer have long-term supply contracts with Generation for their load, the ability of ComEd and PECO to cost-effectively serve their POLR load obligation will depend on the development of such markets.

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        In late 2001, FERC initiated an effort to standardize generator interconnection policies and procedures. When FERC issues a final rule on this subject, it is expected that generators will benefit from not having to deal on a case-by-case basis with different and sometimes inconsistent requirements of different transmission providers.

        Several other actions by FERC should be noted. First, FERC announced in late November 2001 a new market power test, the Supply Margin Assessment (SMA) screen. Under the SMA, if within a particular geographic market an energy company's generation capacity exceeds the market's surplus capacity above peak demand then the test is failed. Where this occurs, FERC will impose on the company and its affiliates a requirement to offer uncommitted capacity under a cost-based rate structure. The only exemption will be for companies operating under the authority of an ISO or RTO with a FERC-approved market monitoring and mitigation plan. Under this approach, it would be unlikely that a vertically integrated energy company serving franchised retail load would be able to pass the test and maintain market-based rates, unless and until the company was a member of an approved ISO or RTO. In December 2001, FERC essentially suspended the applicability of this test, holding that no company would be required to undertake any mitigation until after FERC had held a technical conference on the subject. This technical conference has not been scheduled.

        Second, FERC continues to exhibit a commitment to increased market monitoring with an intent to ensure that high price volatility, such as was seen in California, does not occur again. As part of this commitment, FERC announced early in 2002 the formation of the Office of Market Oversight and Investigation, which will report directly to the FERC Chairman. This new office will assess, among other things, market performance. It is unclear how Generation's business may be impacted by these initiatives.

        Currently, while a significant portion of Generation's capacity is located within the PJM RTO area, other significant generation is located within the Mid-American Interconnected Network (MAIN) reliability region, and is not yet in an approved ISO or RTO. When ComEd joins PJM, most of this capacity will be in an approved RTO. Generation also owns capacity located within the service territory of Illinois Power Company (IP). IP has entered into an agreement to sell its transmission system, and the proposed buyer has notified FERC that it intends to place that system under the control of Midwest Independent Transmission System Operator, Inc., which is also an approved RTO. In the meantime, however, it is possible that under its evolving market power tests, FERC might determine that Generation has market power in this area. If FERC were to suspend Generation's market-based rate authority, it would most likely be necessary to file, and obtain FERC acceptance of, cost-based rate schedules or schedules tied to a public index. In addition, the loss of market-based rate authority would subject Generation to the accounting, record-keeping and reporting requirements that are imposed on public utilities with cost-based rate schedules.

Fuel

        The following table shows sources of electric supply in gigawatthours (GWhs) for 2002 and estimated for 2003:

(1)

Excluding AmerGen.

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(2)

Including PPAs with AmerGen.

        The fuel costs for nuclear generation are substantially less than fossil-fuel generation. Consequently, nuclear generation is the most cost-effective way for Generation to meet its commitment to supply the requirements of ComEd, PECO and certain requirements of Enterprise's competitive retail energy sales business, Exelon Energy Inc. (Exelon Energy), and for sales to other utilities.

        The cycle of production and utilization 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. Generation has uranium concentrate inventory and supply contracts sufficient to meet all of its uranium concentrate requirements through 2004. Generation's contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2005. All of Generation's enrichment requirements have been contracted through 2004. Contracts for fuel fabrication have been obtained through 2005. Generation does not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment or fabrication services for its nuclear units.

        Generation obtains approximately 25% of its uranium enrichment services from European suppliers. There is an ongoing trade action by USEC, Inc. (USEC) 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 (DOC) has assessed countervailing and anti-dumping duties against the European suppliers. Both USEC and the European suppliers have appealed these decisions. Generation is uncertain at this time as to the outcome of the pending appeals, however as a result of these actions Generation may incur higher costs for uranium enrichment services necessary for the production of nuclear fuel.

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

        Substantially all of the natural gas requirements for Generation's Mystic 8 and Mystic 9 units, currently under construction, will be supplied through a twenty-year natural gas contract that became effective on December 1, 2002 with Distrigas of Massachusetts, LLC (Distrigas). The Distrigas facilities consist of a LNG import terminal located adjacent to the Mystic station. Generation is anticipating an additional pipeline gas supply arrangement to supplement LNG supplies to be in service by early 2005.

        Natural gas requirements for operating stations and other stations under construction will be procured through annual, monthly and spot-market purchases. Some fossil generation stations can use either oil or gas as fuel. 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. Generation uses financial instruments to mitigate price risk associated with multi-commodity price exposures. Generation also hedges forward price risk with both over-the-counter and exchange-traded instruments.

Power Team

        Power Team uses Generation's energy generation portfolio, transmission rights and power marketing expertise to manage delivery of energy to wholesale customers, including Energy Delivery, under long-term and short-term contracts, participates in the wholesale energy market to hedge open energy (power and fossil fuels) positions, manages commodity and counterparty credit risks through the use of documented risk and credit policies, and uses its energy market expertise to engage in trading activities for speculative purposes on a limited basis.

        Generation has agreements with ComEd and PECO to supply their respective load requirements for customers through 2004 and 2010, respectively. During 2005 and 2006, ComEd's PPA is a partial

26

requirements agreement under which ComEd will purchase all of its required energy and capacity from Generation, up to the available capacity of the nuclear generating plants formerly owned by ComEd and transferred to Generation. See Item 8. Financial Statements and Supplementary Data—ComEd and PECO Note 2 of the Notes to Consolidated Financial Statements. Generation has also contracted with Exelon Energy, a division of Enterprises, to meet certain supply commitments pursuant to its competitive retail generation sales agreements. Under the agreements with ComEd and PECO, Generation will supply all of ComEd and PECO's needs to supply customers who do not select an alternative electric generation supplier through the end of the respective transition periods. Therefore, the supply requirements under the agreements will vary depending on how much of the load has selected an alternative supplier.

        Power Team has experience in energy markets, generation dispatch and the requirements for the physical delivery of power. Power Team may buy power to meet the energy demand of its customers, including Energy Delivery. These purchases may be made for more than the energy demanded by Power Team's customers. Power Team then sells this open position, along with capacity not used to meet customer demand, in the wholesale energy market. Generation's wholesale operations include the physical delivery and marketing of power obtained through its generation capacity, and long, intermediate and short-term contracts. Generation seeks to maintain a net positive supply of energy and capacity, through ownership of generation assets and power purchase and lease agreements, to protect it from the potential operational failure of one of its owned or contracted power generating units. Generation has also contracted for access to additional generation through bilateral long-term PPAs. These agreements are commitments related to power generation of specific generation plants and/or are dispatchable in nature similar to asset ownership. Generation enters into PPAs with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to customers. Excess power is sold in the wholesale market. Generation has also purchased transmission service to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs. The intent and business objective for the use of its capital assets and contracts is to provide Generation with physical power supply to enable it to deliver energy to meet customer needs.

        Power Team also manages the price and supply risks for energy and fuel associated with generation assets and the risks of power marketing activities. The maximum length of time over which cash flows related to energy commodities are currently being hedged is 4 years. Generation's hedge ratio in 2003 for its energy marketing portfolio is approximately 90%. This hedge ratio represents the percentage of forecasted aggregate annual generation supply that is committed to firm sales, including sales to Energy Delivery's retail load. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand and volatility. During peak periods, the amount hedged declines to assure Generation's commitment to meet Energy Delivery's demand, for which the peak demand is during the summer. For the portion of generation supply that is unhedged, fluctuations in market price of energy will cause volatility in Generation's results of operations.

        Through Power Team, Generation began to use financial and commodity contracts for proprietary trading purposes in the second quarter of 2001 but this activity accounts for a small portion of Power Team's efforts. In 2002, proprietary trading activities resulted in an $18 million after-tax reduction in Generation's earnings. Power Team intends to continue proprietary trading activities but in a more limited capacity given the current lack of liquidity of power markets and reduced number of creditworthy counterparties. The trading portfolio is subject to stringent risk management limits and policies including volume, stop-loss and value-at-risk limits to manage exposure to market risk. Additionally, Generation has a financial risk management policy and a corporate risk group to monitor the financial risks of its power marketing activities. Proprietary trading of derivatives, together with the effects of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards

27

(SFAS) No. 133, "Accounting for Derivatives and Hedging Activities" (SFAS No. 133), may cause volatility in Generation's future results of operations.

        The recent failures of energy companies and their related energy trading practices over the last year have diminished the size and depth of the wholesale energy market. Generation cannot predict how this will affect its trading operations in the future.

        At December 31, 2002, Generation had long-term commitments, relating to the purchase and sale of energy, capacity and transmission rights from and to unaffiliated utilities and others, including the Midwest Generation and AmerGen contracts, as expressed in the following tables:

(1)

On October 2, 2002, Generation notified Midwest Generation of its exercise of termination options under the existing Collins and Peaking PPA. Generation exercised its termination options on 1,727 MWs in 2003 and 2004. In 2003, Generation will take 1,778 MWs of option capacity under the Collins and Peaking Unit Agreements as well as 1,265 MWs of option capacity under the Coal Generation PPA. Net capacity purchases in 2004 include 3,474 MWs of optional capacity from Midwest Generation. Net Capacity Purchases also include capacity sales to TXU under the PPA entered into in connection with the purchase of two generating plants in April 2002, which states that TXU will purchase the plant output from May through September from 2002 through 2006. During the periods covered by the PPA, TXU will make fixed capacity payments and will provide fuel to Generation in return for exclusive rights to the energy and capacity of the generation plants. The combined capacity of the two plants is 2,334 MWs.

(2)

Transmission Rights Purchases include estimated commitments in 2004 and 2005 for additional transmission rights that will be required to fulfill firm sales contracts.

        Additionally, Generation has the following commitments:

        In connection with the 2001 corporate restructuring, Generation entered into a PPA with ComEd under which Generation has agreed to supply all of ComEd's load requirements through 2004. Prices for this energy vary depending upon the time of day and month of delivery. During 2005 and 2006, ComEd's PPA is a partial requirements agreement under which ComEd will purchase all of its required energy and capacity from Generation, up to the available capacity of the nuclear generating plants formerly owned by ComEd and transferred to Generation. Under the terms of the PPA, Generation is responsible for obtaining any required transmission service, subject to ComEd's obligation to obtain network service over the ComEd system. The PPA also specifies that prior to 2005, ComEd and Generation will jointly determine and agree on a market-based price for energy delivered under the PPA for 2005 and 2006. In the event that the parties cannot agree to market-based prices for 2005 and 2006 prior to July 1, 2004, ComEd has the option of terminating the PPA effective December 31, 2004. ComEd will obtain any additional supply required from market sources in 2005 and 2006, and subsequent to 2006, will obtain all of its supply from market sources, which could include Generation.

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        In connection with the 2001 corporate restructuring, Generation entered into a PPA with PECO under which Generation has agreed to supply PECO with substantially all of its electric supply through 2010. Also, under the restructuring, PECO assigned its rights and obligations under various PPAs and fuel supply agreements to Generation. Generation supplies power to PECO from the transferred generation assets, assigned PPAs and other market sources.

Capital Expenditures

        Generation's business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects. As part of Generation's recent acquisition of the assets of Sithe New England, Generation is in the process of completing the construction of three high-efficiency generating facilities with projected capacity of 2,421 MWs of energy. Generation's estimated capital expenditures for 2003 are as follows:

        The majority of Generation's estimated capital expenditures for 2003 are for nuclear fuel and additions to or upgrades of existing facilities.

Sithe

        Generation is a 49.9% owner of Sithe and accounts for the investment as an unconsolidated equity investment. Sithe presently owns 19 generating stations in North America, with approximately 1,321 MWs of net generating capacity and 230 MWs under construction.

        In connection with its initial investment in Sithe, Generation is subject to a Put and Call Agreement (PCA) that gives Generation the right to purchase (Call) the remaining 50.1% of Sithe, and gives the other Sithe shareholders the right to sell (Put) their interest to Generation. At the time of the purchase of Sithe in 2000, the other remaining interests in Sithe were held by Vivendi (34.2%), Marubeni (14.9%) and Sithe management (1%). If the Put option is exercised, Generation has the obligation to complete the purchase.

        The PCA originally provided that the Put and Call options became exercisable as of December 18, 2002 and expired in December 2005. However, upon Apollo Energy, LLC's (Apollo) purchase of Vivendi's and Sithe management's ownership shares, Apollo agreed to delay the effective date of its Put right until June 1, 2003 and, if certain conditions are met, until September 1, 2003. There are also certain events that could trigger Apollo's Put right becoming effective prior to June 1, 2003 including Exelon being downgraded below investment grade by Standard and Poor's Rating Group or Moody's Investors Service, Inc., a stock purchase agreement between Generation and Apollo being executed and subsequently terminated, or the occurrence of any event of default, other than a change of control, under certain Generation or Apollo credit agreements. Depending on the triggering event, Apollo's put price of approximately $460 million, growing at a market rate of interest, needs to be funded within 18 or 30 days of the Put being exercised. There have been no changes to the Put and Call terms with respect to Marubeni's remaining interest.

        The delay in the effective date of Apollo's Put right allows Generation to explore a further restructuring of its investment in Sithe. Generation is continuing discussions with Apollo and Marubeni regarding restructuring alternatives that are designed in part to resolve its ownership limitations of Sithe's qualifying facilities. In addition, Generation is exploring the sale of its interest in Sithe. In the event of a sale, Generation may recognize a one-time loss. Generation would hope to implement any

29

additional restructuring or a sale of its Sithe investment in 2003. If Generation is unsuccessful in restructuring the Sithe transaction or selling its interest and, as a result, purchases the remaining 50.1% of Sithe under the PCA, Generation will proceed to implement measures to address the ownership of the qualified facilities as well as divest non-strategic assets, for which the outcome is uncertain.

        If Generation exercises its option to acquire the remaining outstanding common stock in Sithe, or if all the other stockholders exercise their Put Rights, the purchase price for Apollo's 35.2% interest will be approximately $460 million, growing at a market rate of interest. The additional 14.9% interest will be valued at fair market value subject to a floor of $141 million and a ceiling of $290 million.

        If Generation increases its ownership in Sithe to 50.1% or more, Sithe may become a consolidated subsidiary and Generation's financial results may include Sithe's financial results from the date of purchase. At December 31, 2002, Sithe had total assets of $2.6 billion and total debt of $1.3 billion. This $1.3 billion includes $624 million of subsidiary debt incurred primarily to finance the construction of six generating facilities, $461 million of subordinated debt, $103 million of line of credit borrowings, $43 million of the current portion of long-term debt and capital leases, $30 million of capital leases, and excludes $453 million of non-recourse project debt associated with Sithe's equity investments. For the year ended December 31, 2002, Sithe had revenues of $1.0 billion. As of December 31, 2002, Generation had a $478 million equity investment in Sithe.

        In December 2001, Sithe entered into an 18-month corporate credit facility for $500 million expiring in June 2003. As of November 1, 2002, the credit facility was reduced to $350 million. As of December 31, 2002, Sithe had drawn approximately $103 million under this facility and extended approximately $139 million in letters of credit. Through internally generated cash flows and the corporate credit facility, Sithe has sufficient liquidity to cover all 2003 operating and capital commitments.

AmerGen

        AmerGen was formed in 1997 by PECO and British Energy, to acquire and operate nuclear generation facilities in North America. Currently, AmerGen owns three single-unit nuclear generation facilities, which are described in the table below. AmerGen's nuclear facilities are subject to the provisions and maximum assessment and recovery limits of the Price—Anderson Act and NEIL similar to Generation's, as previously discussed within ITEM 1. Business—Generation, however the American Nuclear Insurers Master Worker Program is not applicable to AmerGen as AmerGen purchased its nuclear reactors after 1998.

        The capacity factors for the AmerGen plants for 2002 and 2001 were 93.4% and 88.5%, respectively. AmerGen operates these nuclear facilities; however, Generation provides AmerGen with many services, including management services, in connection with the operation and support of these facilities under a Services Agreement dated March 1, 1999. In addition, Generation's chief nuclear

30

officer holds the same position at AmerGen. As part of the 2001 corporate restructuring, PECO transferred its 50% interest in AmerGen to Generation.

(1)

AmerGen is reviewing the potential for license renewals for the Oyster Creek Generating Station (Oyster Creek) and Unit 1 of Three Mile Island Nuclear Station (TMI).

        As part of each acquisition of its nuclear facilities, AmerGen entered into a power sales agreement with the seller. The agreement with Illinois Power for Clinton Nuclear Power Station (Clinton) is for 75% of the output for a term expiring at the end of 2004. Generation purchases the residual energy from Clinton through December 31, 2003. The agreement with GPU, Inc. for TMI and Oyster Creek are for all of the output. The agreement for the output of Oyster Creek expires on March 31, 2003. The original agreement for the output of TMI expired in 2001. Generation has agreed to purchase from AmerGen all the energy from TMI after December 31, 2001 through December 31, 2014. AmerGen maintains a decommissioning trust fund for each of its plants in accordance with NRC regulations and believes that amounts in these trust funds, together with investment earnings thereon, and additional contributions for Clinton from Illinois Power will be sufficient to meet its decommissioning obligations.

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

        Generation may transfer its interest in AmerGen, as may British Energy, subject to a right of first refusal of the other party and to the right of the other party to require a third party buying the interest to also purchase the other party's interest and to the right of the non-selling member to veto the proposed transfer. In September 2002, both Generation and British Energy announced that they were considering the possibility of selling their interests in AmerGen. On March 7, 2003, Exelon and British Energy announced that they agreed to reject all offers for the purchase of AmerGen. With the termination of the sale process, Generation announced that it no longer intends to sell its interest in AmerGen.

        In 2002, Generation entered into an agreement to loan AmerGen up to $100 million at an interest rate of 1-month London Interbank Offering Rate plus 2.25%. As of December 31, 2002, the outstanding principal balance of the loan was $35 million. The loan is due July 1, 2003.

        Although Exelon does not anticipate that AmerGen will make any acquisitions in 2003, Exelon has committed to provide AmerGen with capital contributions equivalent to 50% of the purchase price of any acquisitions AmerGen makes in 2003.

        On December 11, 2002, AmerGen received a notice of violation from the New Jersey Department of Environmental Protection for a substantial fish kill, which occurred on September 23, 2002 at Oyster Creek, resulting from the shutdown of dilution pumps during maintenance. The New Jersey

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Department of Environmental Protection has assessed civil penalties and claims for natural damage to the state totaling $373,000 relating to the incident. In addition to the notice of violation, the Attorney General of the State of New Jersey has commenced a criminal investigation into the circumstances surrounding the fish kill. AmerGen is cooperating fully with the Attorney General in its investigation and is working to settle the civil penalty and damage claims in conjunction with the investigation.

Enterprises

        Enterprises consists primarily of the infrastructure services business of InfraSource, Inc. (InfraSource), the energy services business of Exelon Services, Inc., the competitive retail energy sales business of Exelon Energy Company, the district cooling business of Exelon Thermal Holdings, Inc., communications joint ventures and other investments weighted towards the communications, energy services and retail services industries.

        The results of InfraSource's infrastructure services business and Exelon Services' energy services business are dependent on demand for construction and maintenance services. That demand has been driven in the past by the restructuring of the electric utility industry and growth of the communications, cable and internet industries. Slowdown in that restructuring and the current condition of the communications, cable and internet industries means that results will be driven by efforts to manage costs and achieve synergies.

        InfraSource, formerly Exelon Infrastructure Services, Inc., provides infrastructure services, including infrastructure construction, operation management and maintenance services to owners of electric, gas, cable and communications systems, including industrial and commercial customers, utilities and municipalities, throughout the United States. Since it was established in 1997, InfraSource has acquired thirteen infrastructure service companies. In 2002, InfraSource had revenues of approximately $900 million and employed approximately 4,900 at the end of 2002.

        Exelon Services is engaged in the design, installation and servicing of heating, ventilation and air conditioning facilities for commercial and industrial customers throughout the Midwest. Exelon Services also provides energy-related services, including performance contracting and energy management systems.

        Exelon Energy provides retail electric and gas services as an unregulated retail energy supplier in Illinois, Massachusetts, Michigan, New Jersey, Ohio, Pennsylvania and other areas in the Midwest and Northeast United States. Its retail energy sales business is dependent upon continued deregulation of retail electric and gas markets and its ability to obtain supplies of electricity and gas at competitive prices in the wholesale market. The low margin nature of the business makes it important to achieve concentrations of customers with higher volumes so as to manage costs.

        Exelon Thermal provides district cooling and related services to offices and other buildings in the central business district of Chicago and in several other cities in North America. District cooling involves the production of chilled water at one or more central locations and its circulation to customers' buildings, primarily for air conditioning.

        Exelon Communications is the unit of Enterprises through which Exelon manages its communications investments. Exelon Communications' principal investment is PECOAdelphia Communications (PECOAdelphia). PECOAdelphia is a competitive local exchange carrier, providing local and long-distance, point-to-point voice and data communications, internet access and enhanced data services for businesses and institutions in eastern Pennsylvania. PECOAdelphia is a 50% owned joint venture with Adelphia Business Solutions. PECOAdelphia utilizes a large-scale, fiber-optic cable-based network that currently extends over 1,100 miles and is connected to major long-distance carriers and local businesses.

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        On April 1, 2002, Enterprises sold its 49% interest in AT&T Wireless PCS of Philadelphia, LLC to a subsidiary of AT&T Wireless Services for $285 million in cash.

        Exelon Capital Partners was created in 1999 as a vehicle for direct venture capital investing in the areas of unregulated energy sales, energy services, utility infrastructure services, e-commerce and communications. At December 31, 2002, Exelon Capital Partners had direct investments in thirteen companies and investments in four venture capital funds.

        Enterprises is focused on operating its businesses and investments with the goal of maximizing its earnings and cash flow. Enterprises is not currently contemplating any acquisitions. Enterprises expects to divest itself of businesses that are not consistent with Exelon's strategic direction. This does not necessarily mean that an immediate exit will be arranged, but rather businesses may be retained for a period of time if that course of action will strengthen their value.

Employees

        As of December 31, 2002, Exelon and its subsidiaries had approximately 25,200 employees, in the following companies:

        Approximately 6,200 employees, including 4,400 employees of ComEd, 1,700 employees of Generation and 60 employees of BSC are covered by Collective Bargaining Agreements (CBA) with Local 15 of the International Brotherhood of Electrical Workers (IBEW Local 15). The CBA for Generation expires in September 30, 2005. The CBA for ComEd and BSC expires in September 30, 2006. The CBAs provide for a voluntary severance plan.

        In addition to IBEW Local 15, approximately 200 Generation employees are represented by the Utility Workers Union of America. Approximately 5,000 Enterprises employees are represented by unions, including approximately 2,500 employees who are represented by various local unions of the International Brotherhood of Electrical Workers. The remaining union employees are members of a number of different local unions, including laborers, welders, operators, plumbers and machinists.

        PECO employees are not currently covered by a CBA. Over the past several years, a number of unions have filed petitions with the National Labor Relations Board to hold certification elections with regard to different segments of employees within PECO. In all cases, PECO employees have rejected union representation. On August 15, 2002, the International Brotherhood of Electrical Workers filed a petition to conduct a unionization vote of certain of PECO's employees. It is expected that this election will occur in the second quarter of 2003. Exelon expects that such petitions, related to segments of employees at PECO, Generation and Enterprises, will continue to be filed in the future.

Environmental Regulation

General

        Specific operations of Exelon, primarily those of ComEd, PECO, and Generation, are subject to regulation regarding environmental matters by the United States and by various states and local jurisdictions where Exelon operates its facilities. The Illinois Pollution Control Board (IPCB) has jurisdiction over environmental control in the State of Illinois, together with the Illinois Environmental

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Protection Agency, which enforces regulations of the IPCB and issues permits in connection with environmental control. The Pennsylvania Department of Environmental Protection (PDEP) has jurisdiction over environmental control in the Commonwealth of Pennsylvania. The Texas Commission on Environmental Quality has jurisdiction in Texas and Massachusetts Department of Environmental Protection has jurisdiction in Massachusetts. State regulation includes the authority to regulate air, water and noise emissions and solid waste disposals. The United States Environmental Protection Agency (EPA) administers certain Federal statutes relating to such matters, as do various interstate and local agencies.

Water

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

Solid and Hazardous Waste

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

        ComEd, PECO and Generation and their subsidiaries are or are likely to become parties to proceedings initiated by the EPA, state agencies and/or other responsible parties under CERCLA and RCRA with respect to a number of sites, including manufactured gas plant (MGP) sites, or may undertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third party.

        By notice issued in November 1986, the EPA notified over 800 entities, including ComEd and PECO, that they may be PRPs under CERCLA with respect to releases of radioactive and/or toxic substances from the Maxey Flats disposal site, a LLRW disposal site near Moorehead, Kentucky, where ComEd and PECO wastes were deposited. A settlement was reached among the Federal and private PRPs, including ComEd and PECO, the Commonwealth of Kentucky and the EPA concerning their respective roles and responsibilities in conducting remedial activities at the site. Under the settlement, the private PRPs agreed to perform the initial remedial work at the site and the Commonwealth of Kentucky agreed to assume responsibility for long-range maintenance and final remediation of the site. On April 18, 1996, a consent decree, which included the terms of the settlement, was entered by the United States District Court for the Eastern District of Kentucky. The PRPs have entered into a

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contract for the design and implementation of the remedial plan. The work has commenced and is expected to be completed in 2003. Exelon estimates that it will be responsible for approximately $800,000 of the remediation costs to be incurred by the PRPs in implementing the remedial activities specified in the consent decree. As a result of the 2001 corporate restructuring, ComEd's and PECO's liability and obligations arising from the Maxey Flats site have been transferred to Generation.

        By notice issued in December 1987, the EPA notified several entities, including PECO, that they may be PRPs under CERCLA with respect to wastes resulting from the treatment and disposal of transformers and miscellaneous electrical equipment at a site located in Philadelphia, Pennsylvania (the Metal Bank of America site). Several of the PRPs, including PECO, formed a steering committee to investigate the nature and extent of possible involvement in this matter. On May 29, 1991, a Consent Order was issued by the EPA pursuant to which the members of the steering committee agreed to perform the remedial investigation and feasibility study as described in the work plan issued with the Consent Order. PECO's share of the cost of study was approximately 30%. On July 19, 1995, the EPA issued a proposed plan for remediation of the site, which involves removal of contaminated soil, sediment and groundwater and which the EPA estimated would cost approximately $17 million to implement. On June 26, 1998, the EPA issued an order to the non-de minimis PRP group members, and others, including the owner, to implement the remedial design (RD) and remedial action (RA) (Order).

        The PRP group has conducted the RD and submitted to the EPA the revised final design (Final Design) on January 15, 2003. During the design process the PRP group proposed certain revisions to the EPA's preferred remedy, in response to which the EPA has issued two Explanations of Significant Differences (ESD) that are expected to reduce the costs of the preferred remedy. The Final Design estimates the cost to implement the RA to range from $12 million to $15 million. At this time, Exelon cannot predict with reasonable certainty the actual cost of the final remedy, who will implement the remedy, or the cost, if any, to the PRPs or any of its members, including Exelon. The ultimate cost to the PRPs and to Exelon will also depend upon the share of costs that is allocated to the owners and operators of the Metal Bank of America site in litigation that currently is pending in the United States District Court for the Eastern District of Pennsylvania.

MGP Sites

        MGPs manufactured gas in Illinois and Pennsylvania from approximately 1850 to 1950. ComEd generally did not operate MGPs as a corporate entity but did, however, acquire MGP sites as part of the absorption of smaller utilities. Approximately half of these sites were transferred to Nicor Gas as part of a general conveyance in 1954. ComEd also acquired former MGP sites as vacant real estate on which ComEd facilities have been constructed. To date, ComEd has identified 43 former MGP sites for which it may be liable for remediation. Similarly, PECO has identified 28 sites where former MGP activities may have resulted in site contamination. With respect to these sites, ComEd and PECO are presently engaged in performing various levels of activities, including initial evaluation to determine the existence and nature of the contamination, detailed evaluation to determine the extent of the contamination and the necessity and possible methods of remediation, and implementation of remediation. ComEd and PECO are working closely with regulatory authorities in the various locations to develop and implement appropriate plans and schedules for evaluation, risk ranking, detailed study and remediation activities on an individual site and overall program basis. The status of each of the sites in the program varies and is reviewed periodically with the regulatory authorities. At December 31, 2002, ComEd and PECO had accrued $97 million and $28 million, respectively, for investigation and remediation of these MGP sites that currently can be reasonably estimated. ComEd's reserve was increased by $17 million in the third quarter 2002 as the result of a delay in implementing the ongoing remediation for a MGP site in Oak Park, Illinois. ComEd and PECO believe that they could incur additional liabilities with respect to MGP sites, which cannot be reasonably estimated at

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this time. ComEd and PECO have sued a number of insurance carriers seeking indemnity/coverage for remediation costs associated with these former MGP sites.

Air

        Air quality regulations promulgated by the EPA and the various State Environmental Agencies in Pennsylvania, Massachusetts, Illinois and Texas in accordance with the Federal Clean Air Act and the Clean Air Act Amendments of 1990 (Amendments) impose restrictions on emission of particulates, sulfur dioxide (SO₂), nitrogen oxides (NO_x) and other pollutants and require permits for operation of emission sources. Such permits have been obtained by Exelon's subsidiaries and must be renewed periodically.

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

        Generation has completed implementation of measures, including the installation of NO_x emissions controls and the imposition of certain operational constraints, to comply with the Reasonably Available Control Technology limitations and the NO_x Budget Program in the Ozone Transport Region (affecting facilities in Pennsylvania and Massachusetts).

        The EPA has issued two regulations to limit NO_x emissions from power plants in the eastern United States to address the "ozone transport" issue. The first regulation was issued on September 24, 1998. The original NO_xregulation covered power plants in the 22 eastern states and had an effective date of May 1, 2003. As a result of litigation at the D.C. Circuit Court of Appeals, the original NO_x regulation was revised to cover 19 eastern states (rather than the original 22) and the effective date was delayed by approximately one year to May 31, 2004. In most other respects, the court substantively upheld the original NO_x regulation. Massachusetts, Illinois and Pennsylvania power plants are covered by the original NO_xregulation. The second EPA regulation, referred to as the "Section 126 Petition Regulation," was issued on May 25, 1999. This regulation was issued by the EPA in response to downwind state (Connecticut, Maine, Massachusetts, New Hampshire, New York, Pennsylvania, Rhode Island, Vermont) complaints under Section 126 of the Clean Air Act that upwind state NO_x emissions were negatively impacting downwind states' ability to attain the Federal ozone standard. The Section 126 Petition Regulation requires substantively the same NO_x reduction requirement for the power generation sector as the original NO_x regulation. However, the Section 126 Petition Regulation covers a more limited number of states (Delaware, Indiana, Kentucky, Maryland, Michigan, North Carolina, New Jersey, New York, Ohio, Virginia and West Virginia). It does not cover power plants in Illinois. The compliance date of the Section 126 Petition Regulation, originally set for May 1, 2003, was tolled by the D.C. Circuit Court of Appeals pending resolution of several issues. Despite this delay, the northeast states covered by the Section 126 Petition Regulation are still expected to comply with the original May 1, 2003 compliance date. On September 23, 2000, Pennsylvania issued final state NO_xreduction regulations for power plants that satisfy both the original NO_x regulation and the Section 126 Petition Regulation. Regulations are also in place in Massachusetts and Illinois. The Pennsylvania and Massachusetts regulations are effective on May 1, 2003. Exelon has evaluated options for compliance and is installing controls on the two coal units at Eddystone Generating Station (Selective Non-Catalytic Reduction) and the two coal units (Selective Catalytic Reduction) at Keystone Generating Station. In Massachusetts, an Air Quality Improvement Plan is in place for the Mystic Generating Station for compliance with the Massachusetts's multi-pollutant regulations. The plan includes restrictions to residual fuel oil consumption on units 4, 5 and 6; management of low sulfur fuels on unit 7, and dry low NO_x combustors, Selective Catalytic Reduction and CO Oxidation Catalyst on the new gas-fired units 8 and 9 that will achieve commercial operation in 2003. The Exelon NO_x

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compliance program will be supplemented with the purchase of additional NO_x allowances on an as-needed basis. The eight new peaking units commissioned during 2002 at the SE Chicago Generating Station are equipped with NO_x controls that meet requirements for new sources. The Exelon generating stations in the Dallas/Fort Worth (DFW) area are required to comply with the DFW NO_x State Implementation Plan (SIP) that commences on May 1, 2003, with full implementation on May 1, 2005. Additionally, beginning May 1, 2003 these plants must comply with the Emission Banking and Trading of Allowances (EBTA) program established by the enactment of Senate Bill 7 during the 76th Texas Legislative session for the purpose of achieving substantial reductions in NO_x from grandfathered Electric Generating Facilities (EGFs). To comply with both the DFW NO_x SIP and EBTA program, Exelon has embarked on a plan to install NO_x control equipment on several of the units at the Handley and Mountain Creek generating stations

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

        Several other legislative and regulatory proposals regarding the control of emissions of air pollutants from a variety of sources, including utility units, are under active consideration. Exelon is unable at this time to ascertain which proposals may take effect, what requirements they may contain, or how they may affect Exelon's business. At this time, Exelon can provide no assurance that these proposals if adopted will not have a significant effect on Exelon's operations and costs.

Costs

        At December 31, 2002, ComEd, PECO and Generation accrued $101 million, $40 million and $15 million, respectively, for various environmental investigation and remediation. These costs include approximately $97 million at ComEd and $28 million at PECO for former MGP sites as described above. ComEd and PECO cannot currently predict whether they will incur other significant liabilities for additional investigation and remediation costs at sites presently identified or additional sites which may be identified by ComEd and PECO, environmental agencies or others or whether all such costs will be recoverable through rates or from third parties.

        The budgets for expenditures in 2003 at ComEd, PECO and Generation for compliance with environmental requirements total approximately $47 million, $5 million and $2 million, respectively. In addition, ComEd, PECO and Generation may be required to make significant additional expenditures not presently determinable.

Other Subsidiaries of ComEd and PECO with Publicly Held Securities

        ComEd Transitional Funding Trust (ComEd Funding Trust), a Delaware business trust, was formed on October 28, 1998, pursuant to a trust agreement among First Union Trust Company, National Association, now Wachovia Bank, National Association, as Delaware trustee, and two individual trustees appointed by ComEd. ComEd Funding Trust was created for the sole purpose of issuing transitional funding notes to securitize intangible transition property granted to ComEd Funding LLC, a ComEd affiliate, by an ICC order issued July 21, 1998. On December 16, 1998, ComEd Funding Trust issued $3.4 billion of transitional funding notes, the proceeds of which were used to purchase the intangible transition property held by ComEd Funding LLC. ComEd Funding LLC transferred the proceeds to ComEd where they were used, among other things, to repurchase outstanding debt and equity securities of ComEd. The transitional funding notes are solely obligations of ComEd Funding Trust and are secured by the intangible transition property, which represents the right to receive instrument funding charges collected from ComEd's customers. The instrument funding charges represent a nonbypassable, usage-based, per kWh charge on designated consumers of electricity.

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        ComEd Financing I, a Delaware business trust, was formed by ComEd on July 21, 1995. ComEd Financing I was created solely for the purpose of issuing $200 million of trust preferred securities. The trust preferred securities issued on September 26, 1995, carry an annual distribution rate of 8.48% and are mandatorily redeemable on September 30, 2035. The sole assets of ComEd Financing I are $206.2 million principal amount of 8.48% subordinated deferrable interest notes due September 30, 2035, issued by ComEd. On February 14, 2003, ComEd called $200 million of its trust preferred securities at a redemption price of 100% of the principal amount, plus accrued interest to the March 20, 2003 redemption date. The preferred securities were refinanced with trust preferred securities (see ComEd Financing III below).

        Similarly, ComEd Financing II, a Delaware business trust, was formed by ComEd on November 20, 1996. ComEd Financing II was created solely for the purpose of issuing $150 million of trust capital securities. The trust capital securities were issued on January 24, 1997, carry an annual distribution rate of 8.50% and are mandatorily redeemable on January 15, 2027. The sole assets of ComEd Financing II are $154.6 million principal amount of 8.50% subordinated deferrable interest debentures due January 15, 2027, issued by ComEd.

        ComEd Financing III, a Delaware statutory trust, was formed by ComEd on September 5, 2002. ComEd Financing III was created for the sole purpose of issuing and selling preferred and common securities. On March 17, 2003, ComEd Financing III issued $200 million of trust preferred securities, carrying an annual distribution rate of 6.35%, which are mandatorily redeemable on March 15, 2033. The sole assets of ComEd Financing III are $206.2 million principal amount of 6.35% subordinated deferrable interest debentures due March 15, 2033, issued by ComEd. The preferred securities were used to refinance the preferred securities of ComEd Financing I.

        PECO Energy Transition Trust (PETT), a Delaware business trust wholly-owned by PECO, was formed on June 23, 1998 pursuant to a trust agreement between PECO, as grantor, First Union Trust Company, National Association, now Wachovia Bank, National Association, as issuer trustee, and two beneficiary trustees appointed by PECO. PETT was created for the sole purpose of issuing transition bonds to securitize a portion of PECO's authorized stranded cost recovery. On March 25, 1999, PETT issued $4 billion of its Series 1999-A Transition Bonds. On May 2, 2000, PETT issued $1 billion of its Series 2000-A Transition Bonds and on March 1, 2001, PETT issued $805 million of its Series 2001-A Transition Bonds to refinance a portion of the Series 1999-A Transition Bonds. The Transition Bonds are solely obligations of PETT secured by intangible transition property, representing the right to collect transition charges sufficient to pay the principal and interest on the Transition Bonds, sold by PECO to PETT.

        PECO Energy Capital Corp., a wholly-owned subsidiary of PECO, is the sole general partner of PECO Energy Capital, L.P., a Delaware limited partnership (Partnership). The Partnership was created solely for the purpose of issuing preferred securities, representing limited partnership interests and lending the proceeds thereof to PECO and entering into similar financing arrangements. The loans to PECO are evidenced by PECO's subordinated debentures (Subordinated Debentures), which are the only assets of the Partnership. The only revenues of the Partnership are interest on the Subordinated Debentures. All of the operating expenses of the Partnership are paid by PECO Energy Capital Corp. As of December 31, 2002, the Partnership held $128 million aggregate principal amount of the Subordinated Debentures.

        PECO Energy Capital Trust II (Trust II) was created in June 1997 as a Delaware business trust solely for the purpose of issuing trust receipts (Trust II Receipts) each representing an 8.00% Cumulative Monthly Income Preferred Security, Series C (Series C Preferred Securities) of the Partnership. The Partnership is the sponsor of Trust II. As of December 31, 2002, Trust II had outstanding 2,000,000 Trust II Receipts. At December 31, 2002, the assets of Trust II consisted solely of 2,000,000 Series C Preferred Securities with an aggregate stated liquidation preference of $50 million.

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Distributions were made on the Trust II Receipts during 2002 in the aggregate amount of $4 million. Expenses of Trust II for 2002 were approximately $14,000, all of which were paid by PECO Energy Capital Corp. The Trust II Receipts are issued in book-entry only form.

        PECO Energy Capital Trust III (Trust III) was created in April 1998 as a Delaware business trust solely for the purpose of issuing trust receipts (Trust III Receipts) each representing an 7.38% Cumulative Preferred Security, Series D (Series D Preferred Securities) of the Partnership. The Partnership is the sponsor of Trust III. As of December 31, 2002, Trust III had outstanding 78,105 Trust III Receipts. At December 31, 2002, the assets of Trust III consisted solely of 78,105 Series D Preferred Securities with an aggregate stated liquidation preference of $78 million. Distributions were made on Trust III Receipts during 2002 in the aggregate amount of $6 million. Expenses of Trust III for 2001 were approximately $14,000, all of which were paid by PECO Energy Capital Corp. The Trust III Receipts are issued in book-entry only form.

Executive Officers of the Registrants at December 31, 2002

Exelon

ComEd

*

As a result of a reorganization of Exelon's finance function, Mr. Shapard became the principal financial officer of ComEd as of January 22, 2003.

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PECO

*

As a result of a reorganization of Exelon's finance function, Mr. Shapard became the principal financial officer of PECO as of January 22, 2003.

        Each of the above was elected as an officer effective October 20, 2000, the closing date of the Merger, except for Randall E. Mehrberg, who was elected effective December 1, 2000, Robert E. Berdelle, who was elected effective October 11, 2001, Frank F. Frankowski, who was elected effective October 22, 2001, George H. Gilmore Jr., who was elected effective December 3, 2001, Matthew F. Hilzinger, who was elected effective April 1, 2002, and Robert S. Shapard, who was elected effective October 21, 2002.

        Each of the above executive officers holds such office at the discretion of the respective company's board of directors until his or her replacement or earlier resignation, retirement or death.

        Prior to his election to his listed position, Mr. Rowe was President and Co-Chief Executive of Exelon, Co-Chief Executive Officer of ComEd and President, Co-Chief Executive Officer of PECO; Chairman, President and Chief Executive Officer of ComEd and Unicom; and President and Chief Executive Officer of New England Electric System.

        Prior to his election to his listed position, Mr. Kingsley was Executive Vice President of Exelon; Executive Vice President of ComEd and Unicom, President and Chief Nuclear Officer, Nuclear Generation Group of ComEd, and Chief Nuclear Officer of the Tennessee Valley Authority.

        Prior to his election to his listed position, Mr. McLean was Senior Vice President of Exelon; President of the Power Team division of PECO; and Group Vice President of Engelhard Corporation.

        Prior to his election to his listed position, Mr. Mehrberg was Senior Vice President of Exelon; an equity partner with the law firm of Jenner & Block; and General Counsel and Lakefront Director of the Chicago Park District.

        Prior to her election to her listed position, Ms. Moler was Senior Vice President, Government Affairs and Policy of Exelon; Senior Vice President of ComEd and Unicom; Director of Unicom and ComEd; Partner at the law firm of Vinson & Elkins, LLP; Deputy Secretary of the U.S. Department of Energy; and Chair of the Federal Energy Regulatory Commission.

        Prior to his election to his listed position, Mr. Shapard was Executive Vice President and Chief Financial Officer of Covanta Energy Corporation; Executive Vice President and Chief Financial Officer of Ultramar Diamond Shamrock; Chief Executive Officer of TSU Australia, Ltd., and Vice President, Finance and Treasurer at TXU.

        Prior to her election to her listed position, Ms. Strobel was Vice Chairman of ComEd; Vice Chairman of PECO; Executive Vice President and General Counsel of ComEd and Unicom; Senior

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Vice President and General Counsel of ComEd and Unicom; and Vice President and General Counsel of ComEd.

        Prior to his election to his listed position, Mr. Clark was Senior Vice President, Distribution Customer and Marketing Services and External Affairs of ComEd; Senior Vice President of ComEd and Unicom; Vice President of ComEd; Governmental Affairs Vice President; and Governmental Affairs Manager.

        Prior to her election to her listed position, Ms. Gillis was Chief Financial Officer of Exelon, Senior Vice President and Chief Financial Officer of ComEd and Unicom; Vice President and Treasurer of ComEd and Unicom; Vice President, Chief Financial Officer and Treasurer of the University of Chicago Hospitals and Health System; and Senior Vice President and Chief Financial Officer of American National Bank and Trust Company.

        Prior to his election to his listed position, Mr. Gilmore was Group President for National Service Industries, Inc.; President and Chief Operating Officer of Calmat Company; and President of Moore Document Solutions and Moore Business Systems.

        Prior to his election to his listed position, Mr. Lawrence was Senior Vice President, Distribution of PECO; Senior Vice President, Finance and Chief Financial Officer of PECO; and Vice President, Gas Operations division of PECO.

        Prior to his election to his listed position, Mr. Mitchell was Vice President and Treasurer of Exelon; and Vice President, Treasury and Evaluation, and Treasurer of PECO.

        Prior to his election to his listed position, Mr. Skolds was Chief Operating Officer of Exelon Nuclear; and President and Chief Operating Officer of South Carolina Electric and Gas.

        Prior to his election to his listed position, Mr. Snodgrass was Chief Human Resources Officer of Exelon; Senior Vice President of ComEd and Unicom; Vice President of ComEd and Unicom; and Vice President of USG Corporation.

        Prior to his election to his listed position, Mr. Woods was Senior Vice President, Corporate and Public Affairs of PECO; and the Chief of Staff for the Pennsylvania Senate Majority Leader.

        Prior to his election to his listed position, Mr. Hilzinger was Executive Vice President and Chief Financial Officer of Credit Acceptance Corporation; Vice President, Controller of Kmart Corporation; Divisional Vice President, Strategic Planning and Financial Reporting of Kmart Corporation; Assistant Treasurer of Kmart Corporation; and Divisional Vice President, Logistics Finance and Planning of Kmart Corporation.

        Prior to his election to his listed position, Mr. Lewis was Vice President Finance, PECO; Director Nuclear Planning and Development of PECO; and Director of Corporate Development PECO.

        Prior to his election to his listed position, Mr. Dudkin was Vice President Customer and Marketing Services of PECO; and Vice President Power Delivery of PECO.

        Prior to his election to his listed position, Mr. O'Brien was Vice President of Operations of PECO; Director of Transmission and Substations of PECO; and Director of Bucksmont Region of PECO.

        Prior to his election to his listed position Mr. Frankowski was Controller of PECO Energy Company; Manager, Accounting and Control of PECO Energy; and Director—Taxes of PECO Energy Company.

        Prior to his election to his listed position, Mr. Berdelle was Vice President and Comptroller of Unicom and ComEd; Comptroller of Unicom and ComEd; and Manager of Financial Reporting of Unicom and ComEd.

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ITEM 2. PROPERTIES

Energy Delivery

        The electric substations and a portion of the transmission rights of way of ComEd and PECO are owned in fee. A significant portion of the electric transmission and distribution facilities is located over or under highways, streets, other public places or property owned by others, for which permits, grants, easements or licenses, deemed satisfactory by ComEd and PECO, respectively, but without examination of underlying land titles, have been obtained.

Transmission and Distribution

        Energy Delivery's higher voltage electric transmission and distribution lines owned and in service are as follows:

        ComEd's electric distribution system includes 43,100 circuit miles of overhead lines and 30,500 circuit miles of underground lines. PECO's electric distribution system includes 12,890 circuit miles of overhead lines and 8,215 circuit miles of underground lines.

Gas

        The following table sets forth PECO's gas pipeline miles at December 31, 2002:

        PECO has a LNG facility located in West Conshohocken, Pennsylvania that has a storage capacity of 1,200,000 million cubic feet (mmcf) and a send out capacity of 157,000 mmcf/day and a propane-air plant located in Chester, Pennsylvania, with a tank storage capacity of 1,980,000 gallons and a peaking capability of 25,000 mmcf/day. In addition, PECO owns 29 natural gas city gate stations at various locations throughout its gas service territory.

Mortgages

        The principal plants and properties of ComEd are subject to the lien of ComEd's Mortgage dated July 1, 1923, as amended and supplemented, under which ComEd's first mortgage bonds are issued.

        The principal plants and properties of PECO are subject to the lien of PECO's Mortgage dated May 1, 1923, as amended and supplemented, under which PECO's first mortgage bonds are issued.

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Generation

        The following table sets forth Generation's owned net electric generating capacity by station at December 31, 2002:

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(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.

        The net generating capability available for operation at any time may be less due to regulatory restrictions, fuel restrictions, efficiency of cooling facilities and generating units being temporarily out of service for inspection, maintenance, refueling, repairs or modifications required by regulatory authorities.

        Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For information regarding nuclear insurance, see ITEM 1. Business—Generation. Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained. Any such losses could have a material adverse effect on Generation's consolidated financial condition and results of operations.

ITEM 3. LEGAL PROCEEDINGS

Exelon

        Securities Litigation.    Between May 8 and June 14, 2002, several class action lawsuits were filed in the Federal District Court in Chicago asserting nearly identical securities law claims on behalf of purchasers of Exelon securities between April 24, 2001 and September 27, 2001 (Class Period). The complaints allege that Exelon violated Federal securities laws by issuing a series of materially false and misleading statements relating to its 2001 earnings expectations during the Class Period. The court consolidated the pending cases into one lawsuit and has appointed two lead plaintiffs as well as lead counsel.

        On October 1, 2002, the plaintiffs filed a consolidated amended complaint. In addition to the original claims, this complaint contains allegations of new facts and contains several new theories of liability. Exelon believes the lawsuit is without merit and is vigorously contesting this matter.

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ComEd

        Chicago Franchise.    In March 1999, ComEd reached a settlement agreement with Chicago to end the arbitration proceeding between ComEd and Chicago regarding their January 1, 1992 franchise agreement. As part of the settlement agreement, ComEd and Chicago agreed to a revised combination of ongoing work under the franchise agreement and new initiatives that will result in defined transmission and distribution expenditures by ComEd to improve electric services in Chicago. The settlement agreement provides that ComEd would be subject to liquidated damages if the projects are not completed by various dates, unless it was prevented from doing so by events beyond its reasonable control. In addition, ComEd and Chicago established an Energy Reliability and Capacity Account, into which ComEd paid $25 million during each of the years 1999 through 2002, to help ensure an adequate and reliable electric supply for Chicago. No further payments by ComEd into the Energy Reliability and Capacity Account are required.

        On February 20, 2003, ComEd entered into separate agreements with Chicago and with Midwest Generation (Midwest Agreement). Under the terms of the agreement with Chicago, ComEd will pay Chicago $60 million over ten years and be relieved of a requirement, originally transferred to Midwest Generation upon the sale of ComEd's fossil stations in 1999, to build a 500-MW generation facility. Under the terms of the Midwest Agreement, ComEd will receive from Midwest Generation $36 million over ten years, $22 million of which was received on February 20, 2003, to relieve Midwest Generation's obligation under the fossil sale agreement. Midwest Generation will also assume from Chicago a Capacity Reservation Agreement which Chicago had entered into with Calumet Energy Team, LLC (CET), which is effective through June 2012. ComEd will reimburse Chicago for any nonperformance by Midwest Generation under the Capacity Reservation Agreement and will pay approximately $2 million for amounts owed to CET by Chicago at the time the agreement is executed. The net effect of the settlement to ComEd will be amortized over the remaining life of the franchise agreement with Chicago.

        FERC Municipal Request for Refund.    Three of ComEd's wholesale municipal customers filed a complaint and request for refund with FERC, alleging that ComEd failed to properly adjust its rates, as provided for under the terms of the electric service contracts with the municipal customers and to track certain refunds made to ComEd's retail customers in the years 1992 through 1994. In the third quarter of 1998, FERC granted the complaint and directed that refunds be made, with interest. ComEd filed a request for rehearing. On April 30, 2001, FERC issued an order granting rehearing in which it determined that its 1998 order had been erroneous and that no refunds were due from ComEd to the municipal customers. In August 2001, each of the three wholesale municipal customers appealed the April 30, 2001 FERC order to the Federal circuit court, which consolidated the appeals for the purposes of briefing and decision. The Federal circuit court has stayed the proceedings pending settlement negotiations among the parties.

        Retail Rate Law.    In 1996, several developers of non-utility generating facilities filed litigation against various Illinois officials claiming that the enforcement against those facilities of an amendment to Illinois law removing the entitlement of those facilities to state-subsidized payments for electricity sold to ComEd after March 15, 1996 violated their rights under the Federal and state constitutions. The developers also filed suit against ComEd for a declaratory judgment that their rights under their contracts with ComEd were not affected by the amendment. On November 25, 2002, the court granted developers' motions for summary judgment. The judge also entered a permanent injunction enjoining ComEd from refusing to pay the retail rate on the grounds of the amendment, and Illinois from denying ComEd a tax credit on account of such purchases. ComEd and Illinois have each appealed the ruling. ComEd believes that it did not breach the contracts in question and that the damages claimed far exceed any loss that any project incurred by reason of its ineligibility for the subsidized rate. ComEd intends to prosecute its appeal and defend each case vigorously.

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        Service Interruptions.    In August 1999, three class action lawsuits were filed against ComEd, and subsequently consolidated, in the Circuit Court of Cook County, Illinois seeking damages for personal injuries, property damage and economic losses related to a series of service interruptions that occurred in the summer of 1999. The combined effect of these interruptions resulted in over 168,000 customers losing service for more than four hours. Conditional class certification was approved by the court for the sole purpose of exploring settlement. ComEd filed a motion to dismiss the complaints. On April 24, 2001, the court dismissed four of the five counts of the consolidated complaint without prejudice and the sole remaining count was dismissed in part. On June 1, 2001, the plaintiffs filed a second amended consolidated complaint and ComEd has filed an answer. On December 5, 2002, a settlement was reached, pending court approval, whereby ComEd will pay up to $8 million, which includes $4 million paid to date. The settlement, when approved, will release ComEd from all claims arising from the 1999 power outages. A portion of any settlement or verdict may be covered by insurance.

PECO

        None.

Generation

        Godley Park District Litigation.    On April 18, 2001, the Godley Park District filed suit in Will County Circuit Court against ComEd and Generation alleging that oil spills at Braidwood Station have contaminated the Park District's water supply. The complaint sought actual damages, punitive damages of $100 million and statutory penalties. The court dismissed all counts seeking punitive damages and statutory penalties, and the plaintiff has filed an amended complaint before the court. The amended complaint added counts under the Illinois Public Utility Act (PUA), which provides for statutory penalties and allows recovery of attorney's fees. On November 8, 2002, the Godley Park District voluntarily dismissed its lawsuit.

        Cotter Corporation Litigation.    During 1989 and 1991, actions were brought in Federal and state courts in Colorado against ComEd and its subsidiary, Cotter Corporation (Cotter), seeking unspecified damages and injunctive relief based on allegations that Cotter permitted radioactive and other hazardous material to be released from its mill into areas owned or occupied by the plaintiffs, resulting in property damage and potential adverse health effects. In 1994, a Federal jury returned nominal dollar verdicts against Cotter on eight plaintiffs' claims in the 1989 cases, which verdicts were upheld on appeal. The remaining claims in the 1989 actions were settled or dismissed. In 1998, a jury verdict was rendered against Cotter in favor of 14 of the plaintiffs in the 1991 cases, totaling approximately $6 million in compensatory and punitive damages, interest and medical monitoring. On appeal, the Tenth Circuit Court of Appeals reversed the jury verdict, and remanded the case for new trial. These plaintiffs' cases were consolidated with the remaining 26 plaintiffs' cases, which had not been tried. The consolidated trial was completed on June 28, 2001. The jury returned a verdict against Cotter and awarded $16 million in various damages. On November 20, 2001, the District Court entered an amended final judgment that included an award of both pre-judgment and post-judgment interests, costs, and medical monitoring expenses that total $43 million. In November 2000, another trial involving a separate sub-group of 13 plaintiffs, seeking $19 million in damages plus interest was completed in Federal District Court in Denver. The jury awarded nominal damages of $42,500 to 11 of 13 plaintiffs, but awarded no damages for any personal injury or health claims, other than requiring Cotter to perform periodic medical monitoring at minimal cost. Cotter appealed these judgments to the Tenth Circuit Court of Appeals. Cotter is vigorously contesting the awards.

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

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In connection with Exelon's 2001 corporate restructuring, the responsibility to indemnify Cotter for any liability related to these matters was transferred by ComEd to Generation.

        The EPA has advised Cotter that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached barium sulfate at the site. Cotter, along with three other companies identified by the EPA as PRPs, has submitted, a draft feasibility study addressing options for remediation of the site. The PRPs are also engaged in discussions with the State of Missouri and the EPA. The estimated costs of remediation for the site range from $0 to $87 million. Once a remedy is selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. Until an agreement is reached, Generation cannot predict its share of the costs.

        Raytheon Arbitration.    In March 2001, two subsidiaries of Sithe New England Holdings acquired in November 2002, brought an action in the New York Supreme Court against Raytheon Corporation (Raytheon) relating to its failure to honor its guaranty with respect to the performance of the Mystic and Fore River projects, as a result of the abandonment of the projects by the turnkey contractor. In a related proceeding, in May 2002, Raytheon submitted claims to the International Chamber of Commerce Court of Arbitration seeking equitable relief and damages for alleged owner caused performance delays in connection with the Fore River Power Plant Engineering, Procurement & Construction Agreement (EPC Agreement). The EPC Agreement, executed by a Raytheon subsidiary and guaranteed by Raytheon, governs the design, engineering, construction, start-up, testing and delivery of an 800 MW combined-cycle power plant in Weymouth, Massachusetts. Raytheon recently amended its claim and now seeks 141 days of schedule relief (which would reduce Raytheon's liquidated damage payment for late delivery by approximately $25 million) and additional damages of $16 million. Raytheon also has asserted a claim for loss of efficiency and productivity as a result of an alleged constructive acceleration, for which a claim has not yet been quantified. Generation believes the Raytheon assertions are without merit and is vigorously contesting these claims. Hearings by the International Chamber of Commerce Court of Arbitration with respect to liability were held in January and February 2003. A decision on liability is expected to be issued in May 2003 and, if necessary, additional hearings will be held on damages in May and June of 2003.

        Real Estate Tax Appeals.    Generation is involved in tax appeals regarding a number of its nuclear facilities, Limerick Generating Station (Montgomery County, PA), Peach Bottom Atomic Power Station (York County, PA) and Quad Cities Station (Rock Island County, IL). The tax appeal relating to one of its fossil facilities, Eddystone (Delaware County, PA), was resolved during 2002. Generation is also involved in the tax appeal for Three Mile Island (Dauphin County, PA) through AmerGen. Generation does not believe the outcome of these matters will have a material adverse effect on Generation's results of operations or financial condition.

General

        Exelon, ComEd, PECO and Generation are involved in various other litigation matters. The ultimate outcome of such matters, as well as the matters discussed above, while uncertain, are not expected to have a material adverse effect on their respective financial condition or results of operations.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Exelon, ComEd and PECO

        None.

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PART II

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

Exelon

        The information required by this Item with respect to market information relating to Exelon's common stock is incorporated herein by reference to "Market for Registrant's Common Equity and Related Stockholder Matters" in Exhibit 99-2 to Exelon's Current Report on Form 8-K dated February 21, 2003.

ComEd

        As of March 1, 2003, there were outstanding 127,016,425 shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were held by Exelon. At March 1, 2003, in addition to Exelon, there were approximately 280 holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.

PECO

        As of March 1, 2003, there were outstanding 170,478,507 shares of common stock, without par value, of PECO, all of which were held by Exelon.

Exelon, ComEd, PECO and Generation

Dividends

        Under PUHCA, Exelon, ComEd, PECO and Generation can pay dividends only from retained, undistributed or current earnings. Similar restrictions also apply to ComEd under the Illinois Public Utilities Act. However, the SEC has authorized ComEd, and to Exelon, to the extent Exelon receives dividends from ComEd paid from ComEd additional paid-in-capital, to pay up to $500 million in dividends out of additional paid-in capital, although Exelon may not pay dividends out of paid-in capital after December 31, 2002 if its common equity is less than 30% of its total capitalization. At December 31, 2002, Exelon had retained earnings of $2.0 billion, which includes ComEd's retained earnings of $577 million, PECO's retained earnings of $401 million and Generation's undistributed earnings of $924 million. To date, Generation has not declared or paid dividends.

        See ComEd and PECO sections in this item for a further discussion of ComEd and PECO dividend restrictions.

        The following table sets forth Exelon's quarterly cash dividends paid during 2002 and 2001:

(1)

Exelon did not pay any cash dividends in 2000. The first quarter dividend in 2001 was a pro rata dividend. Unicom and PECO each paid their shareholders pro rata, per diem dividends from their last regular dividend dates through October 19, 2000. The first quarter of 2001 covered the 119-day period from the date of the Merger, through the February 15, 2001 record date.

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        The following table sets forth ComEd and PECO's quarterly common dividend payments:

        On January 28, 2003, the Board of Directors of Exelon declared a quarterly dividend of $0.46 per share of Exelon's common stock. This increase of $0.08 per share annually will result in an annual dividend rate of $1.84 per share. Exelon intends to grow its dividend over time at a rate of approximately 4% to 5%, commensurate with long-term earnings growth. The payment of future dividends is subject to approval and declaration by the Board of Directors each quarter.

        ComEd may not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities which were issued to ComEd Financing I, ComEd Financing II and ComEd Financing III (the Financing Trusts); (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of the Financing Trusts; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued (see ITEM 1. Business—Other Subsidiaries of ComEd and PECO with Publicly Held Securities).

        PECO's Articles of Incorporation prohibit payment of any dividend on, or other distribution to the holders of, common stock if, after giving effect thereto, the capital of PECO represented by its common stock together with its retained earnings is, in the aggregate, less than the involuntary liquidating value of its then outstanding preferred stock. At December 31, 2002, such capital was $2.4 billion and amounted to about 17 times the liquidating value of the outstanding preferred stock of $137 million.

        PECO may not declare dividends on any shares of its capital stock in the event that: (1) PECO exercises its right to extend the interest payment periods on the Subordinated Debentures which were issued to the Partnership; (2) PECO defaults on its guarantee of the payment of distributions on the Series C or Series D Preferred Securities of the Partnership; or (3) an event of default occurs under the Indenture under which the Subordinated Debentures are issued (see ITEM 1. Business—Other Subsidiaries of ComEd and PECO with Publicly Held Securities).

ITEM 6. SELECTED FINANCIAL DATA

Exelon

        The information required by this Item is incorporated herein by reference to "Selected Financial Data" in Exhibit 99-1 to Exelon's Current Report on Form 8-K dated February 21, 2003.

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ComEd

        The selected consolidated financial data presented below has been derived from the audited financial statements of ComEd. This data is qualified in its entirety by reference to, and should be read in conjunction with ComEd's Consolidated Financial Statements and Management's Discussion and Analysis of Financial Condition and Results of Operations included herein.

        The information for the year ended 2000 is presented for the periods before and after the Merger. For additional information, see ITEM 8. Financial Statements and Supplementary Data—ComEd, Note 1 and Note 3 of the Notes to Consolidated Financial Statements.

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PECO

        The selected consolidated financial data presented below has been derived from the audited financial statements of PECO. This data is qualified in its entirety by reference to, and should be read in conjunction with PECO's Consolidated Financial Statements and Management's Discussion and Analysis of Financial Condition and Results of Operations included herein.