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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

For the Fiscal Year Ended December 31, 2003

OR

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

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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   x     No  ¨

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.  ¨

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 30, 2003, was as follows:

The number of shares outstanding of each registrant’s common stock as of January 31, 2004 was as follows:

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Exelon Corporation’s Current Report on Form 8-K dated February 20, 2004 containing consolidated financial statements and related information for the year ended December 31, 2003, 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 to be filed prior to April 29, 2004, 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 29, 2004, relating to its annual meeting of shareholders, are incorporated by reference into Part III of this Annual Report on Form 10-K.

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FILING FORMAT

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

FORWARD-LOOKING STATEMENTS

Except for the historical information contained herein, certain of the matters discussed in this Report are forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, 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 factors 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 each of Exelon, ComEd, PECO and Generation, (b) ITEM 8. Financial Statements and Supplementary Data: Exelon - Note 19, ComEd – 15, PECO – Note 14 and Generation – Note 13 and (c) other factors discussed in filings with the United States Securities and Exchange Commission (SEC) by the 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 www.sec.gov and Exelon’s website at www.exeloncorp.com.

The Exelon corporate governance guidelines and the charters of the standing committees of its Board of Directors, together with the Exelon Code of Business Conduct and additional information regarding Exelon’s corporate governance, are available on Exelon’s website at www.exeloncorp.com and will be made available, without charge, in print to any shareholder who requests such documents from Katherine K. Combs, Vice President and Corporate Secretary, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.

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PART I

ITEM 1. BUSINESS

General

Exelon Corporation (Exelon), a registered public utility holding company, through its subsidiaries, operates in three business segments – Energy Delivery, Generation and Enterprises – as described below. See Note 21 of the Notes to Consolidated Financial Statements for further segment information. In addition to Exelon’s three business segments, Exelon Business Services Company (BSC), a subsidiary of Exelon, provides Exelon and its subsidiaries with financial, human resource, legal, information technology, supply management and corporate governance services.

Exelon was incorporated in Pennsylvania in February 1999. Exelon’s principal executive offices are located at 10 South Dearborn Street, Chicago, Illinois 60603, and its telephone number is 312-394-7398.

Energy Delivery

Exelon’s energy delivery business consists of the regulated sale of electricity and distribution and transmission services by Commonwealth Edison Company (ComEd) in northern Illinois and by PECO Energy Company (PECO) in southeastern Pennsylvania and the regulated sale of natural gas and distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia.

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

Exelon’s generation business consists of the owned and contracted for electric generating facilities and energy marketing operations of Exelon Generation Company, LLC (Generation), a 50% interest in Sithe Energies, Inc. (Sithe) and, effective January 1, 2004, the competitive retail sales business of Exelon Energy Company.

Generation was formed in 2000 as a Pennsylvania limited liability company. Generation began operations as a result of a corporate restructuring effective January 1, 2001 in which Exelon separated its generation and other competitive business from its regulated energy delivery business at ComEd and PECO. Generation’s principal executive offices are located at 300 Exelon Way, Kennett Square, Pennsylvania 19348, and its telephone number is 610-765-6900.

Enterprises

Exelon’s enterprise business consists primarily of the energy services business of Exelon Services, Inc. (Exelon Services), the district cooling business of Exelon Thermal Holdings, Inc. (Thermal), the electrical contracting business of F&M Holdings, Inc., a communications joint venture and other investments weighted towards the communications, energy services and retail services industries. Effective January 1, 2004, Enterprises competitive retail sales business, Exelon Energy Company, became part of Generation. Exelon continues to pursue opportunities to sell other Enterprises businesses.

Federal and State Regulation

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

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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). ComEd, PECO 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 United States 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 under PUHCA through March 31, 2004 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. As of December 31, 2003, there was $2.0 billion of financing authority remaining under the SEC order, and Exelon had $1.9 billion of guarantees outstanding subject to PUHCA restrictions. On December 22, 2003, Exelon filed an application requesting financing authorization in an aggregate amount not to exceed $8 billion for a new authorization period, April 1, 2004 through April 15, 2007. 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 the 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. The service territory includes the City of Chicago (Chicago), an area of about 225 square miles with an estimated population of three million. ComEd has approximately 3.6 million customers.

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 2004 to 2060 and subsequent years.

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

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securities and certain other aspects of PECO’s operations. PECO is also subject to regulation by the FERC as to transmission rates, gas pipelines 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 3.9 million, including 1.5 million in the City of Philadelphia. Natural gas service is supplied in an approximate 1,900 square mile area in southeastern Pennsylvania adjacent to Philadelphia, with a population of approximately 2.4 million. PECO delivers electricity to approximately 1.5 million customers and natural gas to approximately 460,000 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.

Energy Delivery’s kilowatthour (kWh) sales and load of electricity are generally higher during the summer periods and 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 21, 2003 and was 22,054 megawatts (MWs); and the highest peak load experienced to date during a winter season occurred on January 6, 2004 and was 15,205 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 15, 2004 and was 6,396 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 send out experienced to date occurred on January 17, 2000 and was 718 million cubic feet (mmcf).

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). 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 generally lies with the customer, POLR obligations make it difficult for the utility to predict and plan for the level of customers and associated energy demand. If POLR 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 the utilities. ComEd and PECO continue to be obligated to provide a reliable delivery system under cost-based rates.

ComEd. All of 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. As of December 31, 2003, no ARES had sought approval from the

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ICC, and no electric utilities have chosen, to enter the residential market for the supply of electricity in ComEd’s service territory. At December 31, 2003, approximately 20,300 non-residential customers, representing approximately 31% 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 to ComEd. ComEd is unable to predict the long-term impact of customer choice on its results of operations.

On November 14, 2002, the ICC allowed ComEd to revise its POLR obligation to be the back-up energy supplier at market-based rates for customers with energy demands of at least three megawatts. About 370 of ComEd’s largest energy customers are affected, representing an aggregate of approximately 2,500 megawatts, and will not have a right to take bundled service after June 2006 or to come back to bundled rates if they choose an alternative supplier. These customers accounted for 10% of ComEd’s 2003 MWh deliveries. On March 28, 2003, the ICC approved changes to ComEd’s 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. An appeal to each of the ICC’s orders is pending and ComEd cannot predict the outcome of those appeals.

The parties to a March 2003 agreement with various Illinois electric retail market suppliers, key customer groups and governmental parties regarding several matters affecting ComEd’s rates for electric service have committed, if specified market conditions exist, not to oppose a process initiated in June 2004 or thereafter for achieving a similar competitive declaration for customers having energy demands of one to three megawatts.

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 two-year average of the earned return on common equity of a utility through December 31, 2006 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 a two-year average of 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 accounting principles generally accepted in the United States (GAAP) and reflect the amortization of regulatory assets. As a result of the Illinois legislation, at December 31, 2003, ComEd had a regulatory asset with an unamortized balance of $131 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 2003, 2002 or 2001 and does not currently expect to trigger the earnings sharing provisions in the years 2004 through 2006.

ComEd expects its capital expenditures will exceed depreciation on its rate base assets through at least 2004. 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.

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.

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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. An extension of this contract for 2005 and 2006 has been agreed to by ComEd and Generation with substantially the same terms as the PPA currently in effect, except for the prices for energy which were reset to reflect the current rates at the time the extension was agreed to. This extension must still be filed with the ICC. Subsequent to 2006, ComEd will obtain all of its supply from market sources, which could include Generation.

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 when the utility can show that the cause of the outage was unpreventable due to weather events or conditions, customer tampering or third-party causes.

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 addressed, among other things, issues related to ComEd’s delivery services rate proceeding, market value index proceeding, the process for competitive service declarations for large-load customers and an amendment and extension of the PPA with Generation. During the second quarter of 2003, the ICC issued orders consistent with the Agreement, which is now effective.

The Agreement provides for a modification of the methodology used to determine ComEd’s market value energy credit. That credit is used to determine the price for specified market-based rate offerings and the amount of the CTC that ComEd is allowed to collect from customers who select an ARES or the PPO. The credit was adjusted upwards through agreed upon “adders” which took effect in June 2003 and has had and will continue to have the effect of reducing ComEd’s CTC charges to customers. Prior to the Agreement, all CTC charges were subject to annual mid-year adjustments based on the forward market prices for on-peak energy and historical market prices for off-peak energy. The Agreement provides that the annual market price adjustment will reflect forward market prices for energy, rather than historical, and allows customers an option to lock in current levels of CTC charges for multi-year periods during the regulatory transition period ending in 2006. These changes provide customers and suppliers greater price certainty and have resulted in an increase in the number of customers electing to purchase energy from alternate suppliers.

The annual market price adjustments to the CTC effective in June 2002 and the impacts of the Agreement in June 2003 had the effect of significantly increasing the CTC charge in June 2002 and subsequently significantly reducing the CTC charge in June 2003. In 2003 and 2002, ComEd collected $304 million and $306 million in CTC revenue, respectively. Based on the changes in the CTC as part of the Agreement and on current assumptions about the competitive price of delivered energy and customers’ choice of electric supplier, ComEd estimates that CTC revenue will be approximately $180 million to $200 million in each of the years 2004 through 2006.

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, 2003, approximately 20% of PECO’s residential load, 24% of its small commercial and industrial load and 5% of its large commercial and industrial load were purchasing generation service from alternative generation suppliers. Customers who purchase energy from an alternative generation supplier continue to pay a delivery charge to PECO.

In addition to retail competition for generation services, PECO’s 1998 settlement of its restructuring case mandated by the Competition Act established caps on generation and distribution rates. The 1998 settlement also

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authorized PECO to recover $5.3 billion of stranded costs and to securitize up to $4.0 billion of its stranded cost recovery, which was subsequently increased to $5.0 billion.

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 was $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 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. Under the settlement agreement entered into by PECO in 2000 relating to the PUC’s approval of the merger among PECO, Unicom Corporation (Unicom), the former parent company of ComEd, and Exelon (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. The remaining required rate reductions are $40 million per year in 2004 and 2005.

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.

PECO has been authorized by the PUC 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 2004 through 2010 as authorized by the PUC based on the level of transition charges established in the settlement of PECO’s restructuring case and the projected annual retail sales in PECO’s service territory. Recovery of transition charges for stranded costs and PECO’s allowed return on its recovery of stranded costs are included in revenues. 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 reconciling adjustments are made quarterly or monthly as needed.

PECO Estimated CTC Revenue and Annual Stranded Cost Amortization 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

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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 1998 settlement of PECO’s restructuring case established market share thresholds (MST) to promote competition. The MST requirements provided that if, as of January 1, 2003, less than 50% of residential and commercial customers have chosen an alternative electric generation supplier, the number of customers sufficient to meet the MST shall be randomly selected and assigned to an alternative electric generation supplier through a PUC-determined process. On January 1, 2003, the number of customers choosing an alternative electric generation supplier did not meet the MST. As a result of a PUC-approved auction process, approximately 64,000 small commercial and industrial customers and 267,000 residential customers were selected to participate in the MST program of which approximately 50,000 and 194,000 customers enrolled with alternative electric generation suppliers in May 2003 and December 2003, respectively. Any customer transferred has the right to return to PECO at any time. Exelon and PECO do not expect the transfer of PECO customers pursuant to the MST plan to have a material impact on their respective results of operations, financial positions or cash flows.

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.

Transmission Services

Energy Delivery provides wholesale and unbundled retail transmission service under rates established by the FERC. The 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. Under the FERC’s open transmission access policy promulgated in Order No. 888, PECO and ComEd, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates. Under the FERC’s Order No. 889, PECO and ComEd are required to comply with the FERC’s Standards of Conduct regulation, as amended, governing the communication of non-public information between the transmission owner’s transmission employees and wholesale merchant employees or the employees of any energy affiliate of the transmission owner. The FERC recently issued Order No. 2004, amending the Standards of Conduct regulation. The amendments do not detrimentally impact Exelon’s business.

In December 1999, the 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.

Order 2000 and the proposed wholesale market platform 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. Under the proposed rule making, 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 would remain responsible for maintaining and physically operating their transmission facilities. The FERC has also issued proposals to encourage FERC-jurisdictional transmission owners to develop RTOs, independent control of the transmission grid and expansion of the transmission grid by providing enhanced returns on equity for transmission assets.

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Order 2000 has not led to the rapid development of RTOs and the FERC has not yet finalized its standard market proposal. 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.

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, 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 April 1, 2003, ComEd received approval from the FERC to transfer control of its transmission assets to PJM. The FERC also accepted for filing the amended PJM Tariff to reflect the inclusion of ComEd and other new members, subject to a compliance filing and to hearing on certain issues. On June 2, 2003, ComEd began receiving electric transmission reservation services from PJM and transferred control of ComEd’s Open Access Same Time Information System to PJM. Although full integration of ComEd’s transmission assets into PJM’s energy market structures was scheduled to occur in November 2003, that date has been delayed due to the August 14, 2003 power blackout in the Northeast United States and Canada. PJM announced that it will conduct an investigation of that blackout and will apply any lessons learned from that investigation to this integration. After resolution of these matters and completion of certain implementation work necessary to integrate ComEd into PJM, ComEd expects to transfer functional control of its transmission assets to PJM and to integrate fully into PJM’s energy market structures during May 2004.

On November 10, 2003, the FERC issued an order allowing ComEd to put into effect beginning April 12, 2004, subject to refund and rehearing, new transmission rates designed to reflect nearly $500 million of infrastructure improvements made since 1998. However, because of the Illinois retail rate freeze and the method for calculating CTCs, the increase is not expected to significantly increase operating revenues. ComEd is unable to predict the ultimate outcome of the associated rehearing or settlement negotiations.

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.

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 rates that PECO may charge for gas service in Pennsylvania. PECO’s purchased gas cost rates, which represent a portion of total 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 rates.

Approximately 30% of PECO’s current total yearly throughput is supplied by third parties. Gas 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

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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 22.0 million dekatherms of underground storage through service agreements. Natural gas from underground storage represents approximately 34% of PECO’s 2003-2004 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 2004:

Approximately 50% of ComEd’s 2004 budgeted capital expenditures and 60% of PECO’s 2004 budgeted capital expenditures are for additions to or upgrades of existing facilities, including improvements to reliability. The remainder of the capital expenditures support customer and load growth.

Generation

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 generation fleet with an experienced wholesale power marketing operation.

At December 31, 2003, Generation owned generation assets in the Northeast, Mid-Atlantic, Midwest and Texas regions with a net capacity of 28,492 MWs, including 16,959 MWs of nuclear capacity. In December 2003, Generation purchased British Energy plc’s (British Energy) 50% interest in AmerGen Energy Company, LLC (AmerGen) for $276.5 million. AmerGen is now a wholly owned subsidiary of Generation. Generation’s ownership interests include 3,145 MWs of capacity owned by Boston Generating, LLC (Boston Generating), a project subsidiary of Exelon New England formerly known as Exelon Boston Generating, LLC of which 2,851 MWs is currently available for commercial operations. Generation controls another 12,703 MWs of capacity in the Midwest, Southeast and South Central regions through long-term contracts.

On November 25, 2003, Generation, Reservoir Capital Group (Reservoir) and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe with put and call options that could result in either party owning Sithe outright. While Generation’s intent is to fully divest Sithe, the timing of the put and call options vary by acquirer and can extend through March 2006. The pricing of the put and call options is dependent on numerous factors, such as the acquirer, date of acquisition and assets owned by Sithe at the time of exercise. Currently, Sithe has a total generating capacity of 1,097 MWs in operation and 228 MWs under construction. See further discussion of these transactions in the Sithe section, which follows within this ITEM 1. Business – Generation.

Generation’s wholesale marketing unit, Power Team, a major wholesale marketer of energy, 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, including the load requirements of ComEd and PECO. Power Team markets any remaining energy in the wholesale bilateral and spot markets.

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Generating Resources

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

The owned generating resources of Generation are located in the Midwest region (approximately 40% of capacity), the Mid-Atlantic region (approximately 39% of capacity), the Northeast region (approximately 12% of capacity) and the Texas region (approximately 9%). Sithe’s generating resources are primarily in New York. The remaining plants are located throughout North America.

In July 2003, Generation announced that it would transition out of its ownership of Boston Generating and the related projects and recorded an asset impairment charge of $945 million (before income taxes) associated with its decision. Boston Generating currently owns 3,145 MWs of generating capacity, of which 2,851 MWs is currently available for commercial operations, located in Massachusetts.

For a further discussion of Sithe and Boston Generating, see the Sithe and Boston Generating sections, which follow within this ITEM 1. Business – Generation.

Nuclear Facilities. Generation has ownership interests in 11 nuclear generating stations, consisting of 19 units with 16,959 MW of capacity. 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 2003, over 50% of Generation’s electric supply was generated from the nuclear generating facilities. During 2003 and 2002, the nuclear generating facilities operated by Generation operated at weighted average capacity factors of 93.4% and 92.7%, respectively.

Licenses. Generation has 40-year operating licenses from the NRC for each of its nuclear units. Generation applied to the NRC in January 2003 for extensions of the operating licenses of Dresden units 2 and 3 and the Quad Cities units. 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

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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. Generation anticipates filing a request for a license extension for Oyster Creek and is currently evaluating the other AmerGen facilities for possible extension. Depreciation provisions are based on the estimated useful lives of the units, which assume the extension of these licenses for all of the non-AmerGen nuclear generating stations. Generation extended the depreciable lives of the AmerGen stations beginning in January 2004 concurrent with its initial full month of 100% ownership.

On May 7, 2003, the NRC announced that it had approved a twenty-year extension of the operating licenses for Peach Bottom Units 2 and 3. The original 40-year license for Peach Bottom Unit 2 was extended to 2033, and the Unit 3 license was extended to 2034.

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 the operation of 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 operating 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 20 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.

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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 2003 indicate that the performance indicators for Generation’s nuclear plants are all in the highest performance band, with the exception of one indicator for Dresden Unit 3, and one indicator for Braidwood Unit 1, both of which are still considered to be in an acceptable performance band within that indicator by the NRC.

Exelon does not know the impact that future terrorist attacks or threats of terrorism may have on the electric and gas industry in general and on Exelon in particular. Exelon has initiated security measures to safeguard its employees and critical operations from threats of terrorism 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. 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 expenses 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 safely stores all SNF generated by nuclear generating facilities in on-site storage pools and, in the case of Peach Bottom, Oyster Creek 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.

As of December 31, 2003, Generation had 41,200 SNF assemblies (9,900 tons) stored on site in SNF pools and dry cask storage. On site dry cask storage in concert with on site storage pools is capable of meeting all current and future SNF storage requirements at Generation’s sites. The following table describes the current status of Generation’s SNF storage facilities:

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

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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 cask storage at its Dresden, Quad Cities, Peach Bottom and Oyster Creek Stations and its consideration of dry cask 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 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 June 2003, the court granted the Government’s motion to dismiss claims other than the breach of contract claims. The trial to determine damages has been set for November 2004.

In July 2000, PECO entered into an agreement (Amendment) with the DOE relating to Generation’s Peach Bottom nuclear generating units to address the DOE’s failure to begin removal of SNF in January 1998 as required by the Standard Contract. Under the Amendment, 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 Amendment also provided 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 the 2001 corporate restructuring.

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 Amendment providing for credits to PECO against nuclear waste fund payments on the ground that such provision is a violation of the NWPA. In September 2002, the United States Court of Appeals for the Eleventh Circuit ruled that the fee adjustment provision of the Amendment violates the NWPA and therefore is null and void. The court did not hold that the Amendment 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 agreement would be rendered null and void, the original Peach Bottom Standard Contract would remain in effect and the parties would return to pre-agreement status. In August 2003, Generation received a letter from the DOE demanding repayment of $40 million of previously received credits from the Nuclear Waste Fund and $1.5 million of accrued interest expense. Generation reserved its ownership share of these amounts in the third quarter of 2003 and has continued to record an interest expense associated with the repayment demand. Generation is in discussions with the DOE regarding a new settlement agreement with a different funding mechanism.

The Standard Contract with the DOE also required 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, 2003, the unfunded liability for the one-time fee with interest was $867 million. The liabilities for SNF 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

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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 2003.

Nuclear 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, 2004, the current limit is $10.9 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance (currently $300 million for each operating site) and the remaining $10.6 billion is provided through mandatory participation in a financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed a maximum charge per reactor per incident. Effective August 20, 2003, the maximum assessment for all nuclear operators per reactor per incident (including a 5% surcharge) increased from $89 million to $101 million, 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 and was subsequently extended to the end of 2003 by the U.S. Congress. Only facilities applying for NRC licenses subsequent to the expiration of the Price-Anderson Act are affected. Existing commercial generating facilities, such as those owned and operated by Generation, remain subject to the provisions of the Price-Anderson Act and are unaffected by its expiration.

Generation is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides property damage, decontamination and premature decommissioning insurance for each station for losses 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 $170 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 NEIL 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. Including the AmerGen sites, Generation’s maximum share of any assessment is $61 million per year. Recovery under this

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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.

For information regarding property insurance, see ITEM 2. Properties – Generation. 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.

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 transferred to Generation from PECO as a result of the 2001 restructuring, the PUC permits PECO to collect from their customers and deposit in nuclear decommissioning trust funds maintained by Generation amounts which, together with earnings theron, will be used to decommission such nuclear facilities. As more fully described below, both ComEd and PECO are currently collecting amounts from rate payers, which are remitted to the trust funds maintained by Generation that will be used to decommission nuclear facilities. Upon adoption of SFAS No. 143, “Asset Retirement Obligations” (SFAS No. 143), Generation was required to re-measure its decommissioning liabilities at fair value and recorded an asset retirement obligation of $2.4 billion on January 1, 2003. Increases in the asset retirement obligation are recorded as operating and maintenance expense. At December 31, 2003, the asset retirement obligation recorded within Generation’s Consolidated Balance Sheet was $3.0 billion including amounts associated with the newly consolidated AmerGen units. 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.

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 ComEd’s customers. The ICC order also provides that any surplus funds after the nuclear stations are decommissioned must be refunded to ComEd’s 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. In 2003, the PUC authorized an annual increase in PECO’s decommissioning cost recovery of approximately $4 million, increasing annual collections to $33 million per year. The amendment is consistent with provisions in PECO’s 1998 settlement of its restructuring case and the Merger settlement, which require PECO to update the cost of decommissioning every five years.

Generation believes that the amounts being remitted to it by ComEd and PECO, Generation’s nuclear decommissioning trust funds and the earnings on these funds will be sufficient to fully fund Generation’s

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decommissioning obligations. See Critical Accounting Policies and Estimates within Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Generation for a further discussion of Nuclear Decommissioning.

AmerGen maintains decommissioning trust funds 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 fully fund its decommissioning obligations.

Zion, a two-unit nuclear generation station, and Dresden Unit 1 have permanently ceased power generation. 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 recorded a liability of $694 million at December 31, 2003, which represents the estimated cost of decommissioning Zion and Dresden Unit 1 in current year dollars. The majority of 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:

Hydroelectric facilities include:

Generation operates all of its fossil and hydroelectric facilities other than La Porte, Keystone, Conemaugh and Wyman. In 2003, approximately 17% of Generation’s electric output was generated from Generation’s owned fossil and hydroelectric generating facilities. The majority of this output was dispatched to support Generation’s power marketing activities.

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 the FERC. The Muddy Run and Conowingo facilities have licenses that expire in September 2014. Generation is considering applying to the FERC for license extensions of 40 years for both plants, but the duration of any license extension will depend on then-current policies at the FERC. The processing of an extension to an existing hydroelectric license generally takes at least eight years.

Insurance. Generation does not carry business interruption insurance for its fossil and hydroelectric operations other than its coverage for Boston Generating. Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon and Generation’s financial condition and their results of operations. For information regarding property insurance, see ITEM 2. Properties – Generation.

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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. In 2003, Generation took 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. On June 25, 2003, Generation notified Midwest Generation of its exercise of its call option under the Coal Generation PPA for 2004. Generation exercised its call option on 687 MWs of capacity for 2004 generated by Waukegan Unit 8 and Fisk Unit 19 and did not exercise its option on 578 MWs of capacity at Waukegan Unit 6, Crawford Unit 7, and Will County Unit 3. On October 1, 2003, Generation notified Midwest Generation of its exercise of certain termination options under the Collins and Peaking Unit Agreements, releasing 303 MWs for 2004, the fifth and final year of the contract. With the exercise of the termination options on the peaking plants in addition to the exercise of the options on the coal plants in June 2003, the contract with Midwest Generation has been finalized for 2004. Generation will take 1,696 MWs of non-option coal capacity, 687 MWs of option coal capacity, 1,084 MWs of Collins Station capacity and 391 MWs of peaking capacity from Midwest Generation in 2004. In total, Generation has retained 3,858 MWs of capacity under the terms of the three existing PPAs with Midwest Generation.

Federal Power Act

The Federal Power Act gives the 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 the FERC’s jurisdiction are required to file rate schedules with the FERC with respect to wholesale sales or transmission of electricity. Tariffs established under FERC regulation give Generation access to transmission lines that enable 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 the FERC’s acceptance of the rate schedules for wholesale sales of electricity. In 2000, Generation received authorization from the FERC to sell energy at market-based rates. As is customary with market-based rate schedules, the 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. The FERC is also authorized to order refunds if it finds that market-based rates are unreasonable. Generation recently filed its required triennial review application to continue its market-based rate authorization.

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As described above under Energy Delivery - Transmission Services, the FERC issued Order No. 2000 to encourage the voluntary formation of RTOs which would provide transmission service across multiple transmission systems. The intended benefits of establishing these entities includes the development of larger markets and the elimination or reduction of 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 have resulted in delays in development of RTOs. PJM has been approved as an RTO, as has the Midwest ISO. ISO New England, the system operator for New England where Generation also owns facilities, currently has an application pending at the FERC for recognition as an RTO.

The FERC also has fostered a standard market platform for the wholesale markets. The FERC proposals 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 manage congestion on transmission lines, preferably by means of a financially-based system known as locational marginal pricing. The FERC has also issued proposals to encourage FERC-jurisdictional transmission owners to develop RTOs, independent control of the transmission grid and expansion of the transmission grid by providing enhanced returns on equity for transmission assets. The FERC’s plans for standard wholesale markets have met substantial opposition from a number of parties, including some state regulators and other governmental officials that it has been attempting to mitigate with public comment and more flexible proposals. The FERC is likely to move forward with these policies allowing regional variations during the coming year.

FERC Order 2000 has not led to the rapid development of RTOs and the FERC has not yet finalized its standard market proposal, due in part to the resistance noted above. Exelon supports both of these proposals but cannot predict whether they will be successful or if they will ultimately lead to the development of large, successful regional wholesale markets.

The FERC issued a final rule establishing standardized generator interconnection policies and procedures. 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 the FERC should be noted. First, the 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, the 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, the FERC essentially suspended the applicability of this test, holding that no company would be required to undertake any mitigation until after the FERC had held a technical conference on the subject. This technical conference has not been scheduled, but the FERC commissioners have stated publicly that the technical conference will be held in early 2004. In the meantime, Generation recently filed its required triennial review of its market-based rates and argued that the SMA screen should exclude from consideration capacity that is committed under long-term contracts to serve POLR load since it cannot be withheld from the market.

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

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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, which 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 may be sold to another utility and may be placed 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, the FERC might determine that Generation has market power in the MAIN region. If the 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 2003 and estimated for 2004:

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 Exelon Energy Company 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 2007. Generation’s contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2007. All of Generation’s enrichment requirements have been contracted through 2007. Contracts for fuel fabrication have been obtained through 2007. 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. alleging dumping in the United States against European enrichment services suppliers. In January 2002, the U.S. International Trade Commission determined that USEC, Inc. was “materially injured or threatened with material injury” by low-enriched uranium exported by European suppliers. The U.S. Department of Commerce has assessed countervailing and anti-dumping duties against the European suppliers. Both USEC, Inc. 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.

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

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Substantially all of the natural gas requirements for Boston Generating’s Mystic 8 and Mystic 9 are 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 liquefied natural gas (LNG) import terminal located adjacent to the Mystic station. See Note 13 of Generation’s Notes to Consolidated Financial Statements for information regarding the guarantee to Distrigas.

Natural gas requirements for operating stations 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 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 three years. Generation’s hedge ratio in 2004 for its energy marketing portfolio is approximately 89%. 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.

Power Team also uses financial and commodity contracts for proprietary trading purposes but this activity accounts for a small portion of Power Team’s efforts. In 2003, proprietary trading activities resulted in an $1 million after-tax increase in Generation’s earnings. The trading portfolio is subject to a risk management policy that includes stringent risk management limits including volume, stop-loss and value-at-risk limits to manage exposure to market risk. Additionally, the corporate risk management group and Exelon’s Risk Management Committee (RMC) monitor the financial risks of the power marketing activities. Proprietary trading of derivatives, together with the application of the provisions of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133), may cause volatility in Generation’s future results of operations.

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At December 31, 2003, 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 contracts, as expressed in the following tables:

Additionally, Generation has the following commitments:

Generation has a PPA with ComEd under which Generation has agreed to supply all of ComEd’s load requirements through 2004. Under the ComEd PPA, prices for energy vary depending upon the time of day and month of delivery. An extension of this contract for 2005 and 2006 has been agreed to by ComEd and Generation with substantially the same terms as the PPA currently in effect, except for the prices of energy which were reset to reflect the current rates at the time the extension was agreed to. This extension must still be filed by ComEd with the ICC. Subsequent to 2006, ComEd will obtain all of its supply from market sources, which could include Generation.

Generation has a PPA with PECO under which Generation has agreed to supply PECO with substantially all of PECO’s electric supply needs through 2010. PECO has also 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 part of AmerGen’s acquisition of its Clinton Nuclear Power Station (Clinton), AmerGen entered into a power sales agreement with the seller, IP. The agreement with IP for Clinton is for 69.5% of the output for a term expiring at the end of 2004.

Capital Expenditures

Generation’s business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects. Generation’s estimated capital expenditures for 2004 are as follows:

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The majority of Generation’s estimated capital expenditures for 2004 are for nuclear fuel and additions to or upgrades of existing facilities.

Boston Generating

On November 1, 2002, Generation purchased the assets of Sithe New England Holdings, LLC (now known as Exelon New England), a subsidiary of Sithe, and related power marketing operations. Exelon New England’s primary assets are gas-fired facilities.

In July 2003, Generation announced that it would transition out of its ownership of Boston Generating, a project subsidiary of Exelon New England, and the related projects and recorded an asset impairment charge of $945 million (before income taxes) associated with its decision. Boston Generating currently owns 3,145 MWs of generating capacity, of which 2,851 MWs are currently available for commercial operations, located in Massachusetts.

The transition out of Generation’s ownership of Boston Generating will take place in a manner that complies with applicable regulatory requirements. For a period of time, Generation expects to continue to provide administrative and operational services to Boston Generating in its operation of the projects. Generation informed the lenders of its decision to exit and that it will not provide additional funding beyond its existing contractual obligations. Generation anticipates that the transition will occur in 2004.

Sithe

On November 25, 2003, Generation, Reservoir and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe. The series of transactions is described below. Immediately prior to these transactions, Sithe was owned 49.9% by Generation, 35.2% by Apollo Energy, LLC (Apollo), and 14.9% by subsidiaries of Marubeni Corporation (Marubeni).

Entities controlled by Reservoir purchased certain Sithe entities holding six U.S. generating facilities, each a qualifying facility under the Public Utility Regulatory Policies Act, in exchange for $37 million ($21 million in cash and a $16 million two-year note); and entities controlled by Marubeni purchased all of Sithe’s entities and facilities outside of North America (other than Sithe Energies Australia (SEA) of which it purchased a 49% interest on November 24, 2003 for separate consideration) for $178 million. Marubeni agreed to acquire the remaining 51% of SEA in 90 days if a buyer is not found, although discussions regarding an extension are ongoing.

Following the sales of the above entities, Generation transferred its wholly owned subsidiary that held the Sithe investment to a newly formed holding company. The subsidiary holding the Sithe investment acquired the remaining Sithe interests from Apollo and Marubeni for $612 million using proceeds from a $580 million bridge financing and available cash. Generation sold a 50% interest in the newly formed holding company for $76 million to an entity controlled by Reservoir. On November 26, 2003, Sithe distributed $580 million of available cash to its parent, which then utilized the distributed funds to repay the bridge financing.

In connection with this transaction, Generation recorded obligations related to $39 million of guarantees in accordance with FASB Interpretation (FIN) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others” (FIN No. 45). These guarantees were issued to protect Reservoir from credit exposure of certain counter-parties through 2015 and other indemnities. In determining the value of the FIN 45 guarantees, Generation utilized a probabilistic model to assess the possibilities of future payments under the indemnifications.

Both Generation and Reservoir’s 50% interests in Sithe are subject to put and call options that could result in either party owning 100% of Sithe. While Generation’s intent is to fully divest Sithe, the timing of the put and

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call options vary by acquirer and can extend through March 2006. The pricing of the put and call options is dependent on numerous factors, such as the acquirer, date of acquisition and assets owned by Sithe at the time of exercise. Any closing under either the put or call options is conditioned upon obtaining state and federal regulatory approvals.

Based on Generation’s interpretation of FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN No. 46-R), it is reasonably possible that Generation will consolidate Sithe as of March 31, 2004. See Note 1 of Generation’s Notes to Consolidated Financial Statements for additional information regarding FIN No. 46-R.

Enterprises

Enterprises consists primarily of the energy services business of Exelon Services, the district cooling business of Thermal, the electrical contracting business of F&M Holdings, Inc., a communications joint venture and other investments weighted towards the communications, energy services and retail services industries. In September 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource, Inc. In December 2003, Enterprises signed agreements to sell the Chicago operations and Aladdin facility of Thermal and certain direct investments held by Enterprises. Effective January 1, 2004, Enterprises competitive retail sales business, Exelon Energy Company, became part of Generation.

InfraSource, prior to its sale in September 2003, provided 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 acquired thirteen infrastructure service companies. For the period through the sale in 2003, InfraSource had revenues of approximately $540 million and, at the time of the sale, had approximately 4,000 employees. At December 31, 2003, F&M Holdings, Inc. is primarily the remaining operations of the former InfraSource with approximately 400 employees. Enterprises is continuing to pursue opportunities to sell F&M Holdings, Inc. in 2004.

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. Enterprises is continuing to pursue opportunities to sell Exelon Services in 2004.

Exelon Energy Company 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 Energy Company became part of Generation effective as of January 1, 2004.

Exelon Thermal provides district cooling and related services to offices and other buildings in the central business district of Chicago and in 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. In December 2003, Enterprises signed agreements to sell the Chicago operations and Aladdin thermal facility.

Exelon Communications is the unit of Enterprises through which Exelon manages its communications investments. Exelon Communications’ principal investment is PECO TelCove, formerly known as PECO Adelphia Communications (PECO TelCove). PECO TelCove is a competitive local exchange carrier, providing local and long-distance, point-to-point voice and data communications, internet access and enhanced data

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services for businesses and institutions in eastern Pennsylvania. PECO TelCove is a 50% owned joint venture with Adelphia Business Solutions, doing business as TelCove. PECO TelCove 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.

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, 2003, Exelon Capital Partners had direct investments in ten 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 an immediate exit from all Enterprises’ businesses, but rather businesses may be retained for a period of time if that course of action will increase their value.

Employees

As of January 1, 2004, Exelon and its subsidiaries had approximately 20,000 employees, in the following companies:

Approximately 5,800 employees, including 4,100 employees of ComEd, 1,600 employees of Generation and 100 employees of BSC, are covered by collective bargaining agreements (CBAs) with Local 15 of the International Brotherhood of Electrical Workers (IBEW) (IBEW Local 15). AmerGen has separate CBAs for each of its nuclear facilities, which cover an aggregate of approximately 700 employees. The Generation CBA with IBEW Local 15 has been extended to expire on September 30, 2007. The CBA for ComEd and BSC expires on September 30, 2008. The Clinton, Oyster Creek and Three Mile Island (TMI) CBAs expire on December 15, 2005, January 31, 2006 and February 29, 2004, respectively. The CBAs provide for a voluntary severance plan.

In addition to IBEW Local 15 and the three IBEW locals covering the AmerGen facilities, approximately 200 Generation employees are represented by the Utility Workers Union of America. Approximately 1,600 Enterprises employees are represented by unions, including approximately 400 employees who are represented by various local unions of the IBEW. The remaining union employees are members of a number of different local unions, including laborers, welders, operators, plumbers and machinists.

During 2003, an election was held at Exelon Power, a division of Generation, that resulted in union representation. Exelon Power and IBEW Local 614 are currently in negotiations for an initial agreement.

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 for different segments of employees within PECO. In all cases, PECO employees have rejected union representation. On August 15, 2002,

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the IBEW filed a petition to conduct a unionization vote of certain of PECO’s employees. On May 21, 2003, the PECO union election was held and a majority of PECO workers voted against union representation. The results of the election have not been certified due to pending challenges and objections. 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 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 the 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.

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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 disposed of low level radioactive wastes resulting from their nuclear generation activities, which are now the responsibility of Generation. A settlement was reached among the Federal and private PRPs, including ComEd and PECO, the Commonwealth of Kentucky (Kentucky) and the EPA concerning their respective roles and responsibilities in conducting remedial activities at the site. Under the settlement, which was incorporated into a Federal court Consent Decree, the private PRPs agreed to perform the initial remedial work at the site and Kentucky agreed to assume responsibility for long-range maintenance and final remediation of the site. On October 5, 2003, the EPA issued a Certificate of Completion indicating that the private PRPs have completed their obligations under the Consent Decree. The site is being turned over to Kentucky as provided in the Consent Decree. The private PRPs, including Generation, will maintain oversight of Kentucky’s activities to assure the stability of the site since the private PRPs have residual liability if there is a remedy failure over the next ten years.

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 the 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 and remedial action.

The PRP group has conducted the remedial design and submitted to the EPA the revised 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 that are expected to reduce the costs of the preferred remedy. The final design estimates for the cost to implement the remedial action range from $12 million to $15 million. At this time, PECO 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 PECO. The ultimate cost to the PRPs and to PECO 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 42 former MGP sites for which it may be liable for remediation. Of these 42 sites, the Illinois Protection Agency has approved the clean-up of three sites. Similarly, PECO has identified 27 sites where former MGP activities may have resulted in site contamination. Of these 27 sites, the Pennsylvania Department of Environmental Protection has approved the clean-up of six sites. 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 jurisdictions 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

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reviewed periodically with the regulatory authorities. At December 31, 2003, ComEd and PECO had accrued $64 million (discounted) and $41 million (discounted), respectively, for investigation and remediation of these MGP sites that currently can be reasonably estimated. ComEd’s reserve was increased by $17 million during 2002 and an additional $12 million during 2003 in connection with the ongoing remediation for a MGP site in Oak Park, Illinois. The remediation of the Oak Park site was substantially complete as of December 31, 2003. However, there are several personal injury and property damage claims pending related to this site. ComEd and PECO believe that they could incur additional liabilities with respect to MGP sites, which cannot be reasonably estimated at this time. PECO has sued, and ComEd is in negotiations, with a number of insurance carriers seeking indemnity/coverage for remediation costs associated with these former MGP sites. Additionally, PECO is currently collecting through regulated gas rates, revenues to offset expenditures on MGP site remediation.

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 desulphurization 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 state-level ozone season (May to September) NO_x reduction regulations. These state-level regulations were developed by eastern states to reduce summertime NO_x emissions pursuant to several Federal NO_x reduction regulations adopted by the Federal EPA during 1998 and 1999 to address regional “ozone transport.” State level NO_x reduction regulations took effect May 1, 2003 in Pennsylvania and Massachusetts. Compliance in Illinois is required starting May 31, 2004. Texas is not covered by the EPA’s ozone transport regulations. When fully implemented on May 31, 2004, the EPA’s ozone transport regulations will require 19 eastern states to reduce summertime NO_x emissions.

Exelon has evaluated options for compliance with the new NO_x regulations and installed controls on the two coal-fired units at the Eddystone Generating Station (Selective Non-Catalytic Reduction) and installed controls on the two coal-fired units (Selective Catalytic Reduction) at the 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 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 achieved commercial operation in 2003. Generation’s NO_x 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 Southeast 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 commenced 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. To comply with both the DFW NO_x SIP and EBTA program, Generation has embarked on a plan to install NO_x control equipment on several of the units at the Handley and Mountain Creek generating stations.

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Many other provisions of the Amendments affect activities of Exelon’s businesses, primarily Generation. The Amendments establish stringent control measures for geographical regions which have been determined by the EPA not to meet National Ambient Air Quality Standards (NAAQS); 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 generating plants, are under active consideration. On the Federal legislative front, several multi-pollutant bills have been introduced in Congress that would reduce generating plant emissions of NO_x, SO₂, mercury and/or carbon dioxide starting late this decade. On the Federal regulatory front, the EPA announced in December 2003 its intention to publish several proposed regulations in the Federal Register during early 2004. One proposed regulation would require a reduction in mercury emissions from coal-fired plants, and establish nickel emission standards for oil-fired plants later this decade. Another proposed regulation, “Interstate Air Quality Rule,” would require further reductions of NO_x and SO₂ emissions in the eastern United States in two phases (2010 and 2015) to support regional attainment of the new federal NAAQS for fine particulate (PM2.5) and ground level ozone (8-hour standard). 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 businesses. 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, 2003, ComEd, PECO and Generation accrued $69 million, $50 million and $10 million, respectively, for various environmental investigation and remediation. These costs include approximately $64 million at ComEd and $41 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 2004 at ComEd, PECO and Generation for compliance with environmental requirements total approximately $10 million, $9 million and $3 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

Effective December 31, 2003, ComEd Funding LLC, ComEd Transitional Funding Trust, ComEd Financing II, ComEd Financing III, PECO Energy Transition Trust, and PECO Energy Capital Trust III were deconsolidated from the financial statements of Exelon, ComEd, and PECO in accordance with FIN No. 46-R. Effective July 1, 2003, PECO Energy Capital Trust IV, a financing subsidiary created in May 2003, was deconsolidated from the financial statements of Exelon and PECO in accordance with FIN No. 46, prior to its subsequent revision in December 2003. Amounts owed to these financing trusts were recorded as long-term debt to affiliates, long-term debt to ComEd Transitional Funding Trust and long-term debt to PECO Energy Transitional Trust debt to PECO Energy Transitional Trust within the Consolidated Balance Sheets, and interest owed to these entities subsequent to the adoption of FIN No. 46 and FIN No. 46-R was recorded as interest expense to affiliates within the Consolidated Statements of Income. Prior periods were not restated.

ComEd Transitional Funding Trust (ComEd Funding Trust), a Delaware statutory 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

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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 non-bypassable, usage-based, per kWh charge on designated consumers of electricity.

ComEd Financing I, a Delaware statutory 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, carried an annual distribution rate of 8.48% and were mandatorily redeemable on September 30, 2035. The sole assets of ComEd Financing I were $206 million principal amount of 8.48% subordinated deferrable interest notes due September 30, 2035, issued by ComEd. On March 20, 2003, ComEd Financing I redeemed all of its trust preferred securities at a redemption price of 100% of the liquidation amount, plus accrued distributions to the redemption date. ComEd redeemed $206 million of its 8.48% subordinated debentures issued to ComEd Financing I. The preferred securities were refinanced with trust preferred securities (see ComEd Financing III below).

ComEd Financing II, a Delaware statutory 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 $155 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 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 statutory trust wholly owned by PECO, was formed on June 23, 1998 pursuant to a trust agreement among 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.

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 deferrable interest 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, 2003, the Partnership held $78 million aggregate principal amount of the Subordinated Debentures.

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PECO Energy Capital Trust II (Trust II) was created in June 1997 as a Delaware statutory trust solely for the purpose of issuing $50 million 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. In June 2003, Trust II redeemed all of its 8% trust preferred securities at a redemption price of $25 per trust receipt, plus accrued and unpaid distributions. The preferred securities were refinanced with trust preferred securities (see Trust IV below).

PECO Energy Capital Trust III (Trust III) was created in April 1998 as a Delaware statutory trust solely for the purpose of issuing $78 million 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, 2003, Trust III had outstanding 78,105 Trust III Receipts. At December 31, 2003, the assets of Trust III consisted solely of 78,105 Series D Preferred Securities with an aggregate stated liquidation preference of $78 million.

PECO Energy Capital Trust IV (Trust IV) was created in May 2003 as a Delaware statutory trust solely for the purpose of issuing $100 million trust preferred securities and common securities and purchasing the 5.75% deferrable interest subordinated debentures. PECO is the sole owner of all of the common securities of the Trust IV. The sole assets of Trust IV are $100 million principal amount of 5.75% subordinated debentures issued by PECO.

Executive Officers of the Registrants at December 31, 2003

Exelon

ComEd

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PECO

Generation

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 3, 2001, Matthew F. Hilzinger, who was elected effective April 15, 2002, Robert S. Shapard, who was elected effective October 21, 2002, Michael B. Bemis, who was elected effective August 12, 2002, John F. Young, who was elected effective March 3, 2003, and Duane M. DesParte, who was elected effective February 17, 2003.

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.

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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 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. Bemis was Chief Executive Officer of Entergy’s London Electricity PLC; and Chairman and CEO of Master Graphics, Inc.

Prior to his election to his listed position, Mr. Snodgrass was Chief Administrative 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. 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. 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 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. DesParte was Partner at Deloitte & Touche LLP; and Partner at Arthur Andersen LLP.

Prior to his election to his listed position, Mr. O’Brien was Executive Vice President of PECO; 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. 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. Young was Senior Vice President of Sierra Pacific Resources Corporation; President of Avalon Consulting; and Executive Vice President of Southern Generation.

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 at December 31, 2003 were as follows:

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ComEd’s electric distribution system includes 43,400 circuit miles of overhead lines and 31,700 circuit miles of underground lines. PECO’s electric distribution system includes 12,900 circuit miles of overhead lines and 8,327 circuit miles of underground lines.

Gas

The following table sets forth PECO’s gas pipeline miles at December 31, 2003:

PECO has an LNG facility located in West Conshohocken, Pennsylvania which has a storage capacity of 1,200 mmcf and a send-out capacity of 157 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 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.

Insurance

ComEd and PECO maintain property insurance against loss or damage to Energy Delivery’s properties by fire or other perils, subject to certain exceptions. ComEd and PECO are 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 the consolidated financial condition or results of operations of ComEd or PECO.

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Generation

The following table sets forth Generation’s owned net electric generating capacity by station at December 31, 2003:

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