UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

For the Fiscal Year Ended December 31, 2004

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

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, 2004, was as follows:

The number of shares outstanding of each registrant’s common stock as of January 31, 2005 was as follows:

TABLE OF CONTENTS

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FILING FORMAT

This combined Form 10-K is being filed separately 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

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 Operation—Business Outlook and the Challenges in Managing the Business for each of Exelon, ComEd, PECO and Generation, (b) ITEM 8. Financial Statements and Supplementary Data: Exelon—Note 21, ComEd—16, PECO—Note 15 and Generation—Note 17 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 a registrant files 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. Information contained on Exelon’s website shall not be deemed incorporated into, or to be a part of, this Report.

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, a registered public utility holding company, through its subsidiaries, operates in three business segments—Energy Delivery, Generation and Enterprises—as described below. See Note 22 of Exelon’s 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.

Proposed Merger with Public Service Enterprise Group Incorporated

On December 20, 2004, Exelon entered into an Agreement and Plan of Merger (Merger Agreement) with Public Service Enterprise Group Incorporated (PSEG), the holding company for an electric and gas utility company primarily located and serving customers in New Jersey, whereby PSEG will be merged with and into Exelon (Merger). Under the Merger Agreement, each share of PSEG common stock will be converted into 1.225 shares of Exelon common stock. As of December 31, 2004, PSEG’s market capitalization was over $12 billion. Additionally, PSEG, on a consolidated basis, has approximately $14 billion of outstanding debt which is currently anticipated to become part of Exelon’s consolidated debt.

The Merger Agreement contains certain termination rights for both Exelon and PSEG, and further provides that, upon termination of the Merger Agreement under specified circumstances, (i) Exelon may be required to pay PSEG a termination fee of $400 million plus PSEG’s transaction expenses up to $40 million and (ii) PSEG may be required to pay Exelon a termination fee of $400 million plus Exelon’s transaction expenses up to $40 million. The Merger Agreement has been unanimously approved by both companies’ boards of directors but is contingent upon, among other things, the approval by shareholders of both companies, antitrust clearance and a number of regulatory approvals or reviews by federal and state energy authorities. The parties have made certain of the regulatory filings to obtain necessary regulatory approvals. It is anticipated that this approval process will be completed and the Merger will close within 12 months to 15 months after the announcement of the Merger Agreement in December 2004. Further information concerning the proposed Merger is included in the preliminary joint proxy statement/prospectus contained in the registration statement on Form S-4 filed by Exelon in connection with the Merger. For additional information related to the Merger, see ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Exelon—Executive Overview—Proposed Merger with PSEG and Note 2 of Exelon’s Notes to Consolidated Financial Statements.

Energy Delivery

Exelon’s energy delivery business consists of the purchase and regulated sale of electricity and distribution and transmission services by ComEd in northern Illinois, including the City of Chicago, and by PECO in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated sale of natural gas and distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia (collectively, Energy Delivery).

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

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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 19103 and its telephone number is 215-841-4000.

Generation

At December 31, 2004, Exelon’s generation business consists of the owned and contracted-for electric generating facilities and energy marketing operations of Generation, a 50% interest in Sithe Energies, Inc. (Sithe), 49.5% interests in two power stations in Mexico and the competitive retail sales business of Exelon Energy Company (Exelon Energy). On January 31, 2005, Exelon purchased the remaining 50% of Sithe and immediately sold its entire interest in Sithe.

Exelon Generation Company, LLC 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 businesses 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 enterprises business is comprised of infrastructure and electrical contracting services of Exelon Enterprises Company, LLC (Enterprises) and other investments weighted towards the communications and energy services industries. During 2004 and 2003, Enterprises exited a significant number of businesses and investments. Exelon plans to divest or wind down the remaining assets of Enterprises during 2005.

Federal and State Regulation

Exelon, a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA), is subject to Federal and state regulation. ComEd is a public utility under the Illinois Public Utilities Act subject to regulation by the Illinois Commerce Commission (ICC). PECO is a public utility under the Pennsylvania Public Utility Code subject to regulation by the Pennsylvania Public Utility Commission (PUC). 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).

Exelon is subject to a number of restrictions under PUHCA. These restrictions generally involve financing, investments and affiliate transactions. Under PUHCA, Exelon cannot issue debt or equity securities or guarantees without approval of the United States Securities and Exchange Commission (SEC) or, in the case of ComEd and PECO, the ICC and the PUC, respectively. On April 1, 2004, Exelon obtained a new order under PUHCA authorizing, through April 15, 2007, financing transactions, including the issuance of common stock, preferred securities, equity-linked securities, long-term debt and short-term debt in an aggregate amount not to exceed $8.0 billion above the amount outstanding for the Exelon holding company and Generation at December 31, 2003. No securities have been issued under the above described limit as of December 31, 2004. Exelon is also authorized to issue up to $6.0 billion in guarantees or letters of credit or otherwise provide credit support with respect to the obligations of their subsidiaries and non-affiliated third parties in the normal course of business. As of December 31, 2004, Exelon had $2.0 billion of guarantees and letters of credit outstanding pursuant to SEC authorization.

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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, exempt wholesale generating businesses and foreign utility companies (these investments are capped at $4 billion in the aggregate), energy-related companies (as defined in SEC rules and subject to a cap on these investments of 15% of Exelon’s consolidated capitalization), and 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 Operation—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 ComEd’s 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, an area of about 225 square miles with an estimated population of three million. ComEd has approximately 3.7 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 2005 to 2060 and subsequent years. ComEd anticipates working with the appropriate agencies to extend or replace the franchise agreements upon expiration.

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 Philadelphia. PECO is subject to extensive regulation by the PUC as to electric and gas rates, the issuances of certain 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 PECO’s business.

PECO’s retail service territory has an area of approximately 2,100 square miles and an estimated population of 3.8 million. PECO provides electric delivery service in an area of approximately 2,000 square miles, with a population of approximately 3.7 million, including 1.5 million in Philadelphia. Natural gas service is supplied in an area of approximately 1,900 square miles in southeastern Pennsylvania adjacent to Philadelphia, with a population of approximately 2.3 million. PECO delivers electricity to approximately 1.5 million customers and natural gas to approximately 460,000 customers.

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PECO has the necessary authorizations to furnish regulated electric and gas service in the various municipalities or territories in which it now supplies such services. PECO’s authorizations consist of charter rights and certificates of public convenience issued by the PUC and/or “grandfather rights.” These rights are generally unlimited as to time and are generally exclusive from competition from other electric and gas utilities. In a few defined municipalities, PECO’s gas service territory authorizations overlap with that of another gas utility but PECO does not consider those situations as posing a material competitive or financial threat.

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 occurred on August 21, 2003 and was 22,054 megawatts (MWs); its highest peak load during a winter season occurred on December 22, 2004 and was 15,222 MWs. PECO’s highest peak load occurred on August 14, 2002 and was 8,164 MWs; its highest peak load during a winter season occurred on December 20, 2004 and was 6,838 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 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 regulated. The legislation and related regulatory orders in both states allow customers to choose an alternative electric generation supplier; required rate reductions and imposed freezes or caps on rates during a transition period following the adoption of the legislation; and allow the collection of competitive transition charges (CTCs) from customers to recover costs that might not otherwise be recovered in a competitive market (stranded costs) during the transition period.

Under Illinois and Pennsylvania legislation, ComEd and PECO are required to provide generation services to customers, except for certain large customers of ComEd, 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 to those customers who do not take service from an alternative generation supplier or who choose to return 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.

ComEd. All of ComEd’s customers are eligible to choose an alternative electric supplier and most 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, 2004, no alternative electric supplier had approval from the ICC, and no electric utilities had chosen to enter the residential market for the supply of electricity in ComEd’s service territory. At December 31, 2004, approximately 22,100 non-residential customers, representing approximately 35% of ComEd’s annual retail kilowatthour sales, had elected to purchase their electric energy from an alternative electric supplier or had chosen the PPO. Customers who receive energy from an alternative electric supplier and customers who have elected the PPO continue to pay a delivery charge to ComEd, which generally includes a CTC. 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, by operation of law, to revise its POLR obligation to be the back-up energy supplier at market-based rates for certain customers with energy demands of at least three MWs. About 370 of ComEd’s largest energy customers are affected,

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representing an aggregate of approximately 2,500 MWs. These customers will not have a right to take bundled service after June 2006 or to return to bundled rates if they choose an alternative supplier prior to June 2006. On March 28, 2003, the ICC approved changes to ComEd’s real-time pricing tariff for non-residential customers, including those with energy demands of at least three MWs who choose hourly energy supply for their electric power and energy. These ICC orders were affirmed on appeal.

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 (20 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. Under the Illinois statue, any impairment of goodwill has no impact on the determination of the cap on ComEd’s allowed equity return during the transition period. As a result of the Illinois legislation, at December 31, 2004, ComEd had a regulatory asset related to recoverable transition costs with an unamortized balance of $87 million, which 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 in 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 has not triggered the earnings sharing provision through 2004 and does not currently expect to trigger the earnings sharing provision in 2005 or 2006.

ComEd expects its capital expenditures will exceed depreciation on its rate base assets through at least 2005. The base rate freeze, coupled with other provisions of the Illinois restructuring law, generally precludes 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 remaining period of the rate freeze and until rate increases are approved authorizing a return of and on this new investment.

The rates for the generation service provided by ComEd under bundled rates are subject to a rate freeze during the transition period ending December 31, 2006. ComEd has entered into a power purchase agreement (PPA) with Generation under which Generation has agreed to supply all of ComEd’s load requirements through 2006. Prices for this energy vary depending upon the time of day and month of delivery. Subsequent to 2006, ComEd expects to procure all of its supply from market sources, which could include Generation.

The Illinois legislation also provided for the collection of a CTC from customers who choose to purchase electric energy from an alternative electric supplier or elect the PPO during the transition period which extends through 2006. The CTC 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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ComEd’s market value energy 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 alternative electric supplier 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 CTCs to customers. Prior to 2003, all CTCs 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 current annual market price adjustment reflects forward, rather than historical, market prices for off-peak energy and allows customers to lock in current levels of CTCs 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.

In 2004 and 2003, ComEd collected $169 million and $304 million in CTC revenues, respectively. As a result of increasing mitigation factors, changes in energy prices and the ability of certain customers to establish fixed, multi-year CTC rates beginning in 2003, ComEd estimates that CTC revenue will amount to approximately $90 million to $110 million in each of the years 2005 and 2006.

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. During the years 2002, 2003 and 2004, ComEd did not have any outages that triggered the reimbursement requirement.

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, 2004, approximately 4% of PECO’s residential load, 23% of its small commercial and industrial load and 6% of its large commercial and industrial load were purchasing generation service from alternative generation suppliers. Customers who purchase energy from an alternative electric 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 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 2004, 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 (PECO / Unicom Merger), PECO agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through December 31, 2005 and extended the rate cap on distribution rates through December 31, 2006. The remaining required rate reductions are $40 million in 2005.

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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 the customer purchases electricity from the utility or an alternative electric 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%. See the “Business Outlook and the Challenges Managing the Business” section of ITEM 7 of this Form 10-K for the estimated revenues and amortization expense associated with CTC collection and stranded cost recovery through 2010.

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

PECO has entered into a PPA with Generation under which PECO obtains substantially all of its electric supply from Generation through 2010. Prices for this energy vary depending upon the time of day and month of delivery. Subsequent to 2010, PECO expects to procure all of its supply from market sources, which could include Generation.

In November 2004, Pennsylvania adopted Act 213, the Alternative Energy Portfolio Standards (AEPS) Act of 2004. For more information, see “Environmental Regulation—Renewable and Alternative Energy Portfolio Standards” below.

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, ComEd and PECO, 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, ComEd and PECO 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 affect Exelon’s business.

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PJM Interconnection, LLC (PJM) is the independent system operator and the FERC-approved regional transmission organization (RTO) for the Mid-Atlantic and Midwest regions 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 controls through central dispatch the day-to-day operations of the bulk power system of the PJM region. ComEd and PECO are members of PJM, and their transmission systems are currently under the dispatch control of PJM. 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.

The FERC has attempted to expand the development of regional markets, which has generated substantial opposition from some state regulators and other governmental bodies. In addition, efforts to develop an RTO have been abandoned in certain regions. Notwithstanding these difficulties, the Midwest Independent System Operator, Inc. (MISO), has been certified as an RTO by FERC. MISO is attempting to develop central generation dispatch and transmission operations across the Midwestern United States, contiguous to PJM’s footprint. The FERC has ordered the elimination of rate barriers and protocol differences between MISO and PJM. Exelon supports the development of RTOs and implementation of standard market protocols, but cannot predict their success or whether they will lead to the development of the envisioned large, successful wholesale markets. The development of large competitive wholesale electricity markets would facilitate an auction to meet ComEd’s and PECO’s POLR load obligations with reliable wholesale electricity supply when their PPAs with Generation expire.

In November 2004, the FERC issued two orders authorizing ComEd and PECO to recover from various entities revenue representing amounts ComEd and PECO will lose as a result of the elimination of through and out (T&O) charges, for energy flowing across ComEd’s and PECO’s transmission systems, that were terminated pursuant to the FERC orders effective December 1, 2004. The collection of this revenue will be over a transitional period of December 1, 2004 through March 31, 2006. Several parties have sought rehearing of the FERC orders and there likely will be appeals filed in the matter after the rehearing order is issued. During 2004 prior to the termination of the T&O charges, ComEd and PECO collected net T&O charges of approximately $50 million and $3 million, respectively. As a result of the proceeding, ComEd may see reduced net collections and PECO may become a net payer of these charges. The ultimate outcome of this proceeding is uncertain and may have a material adverse effect on ComEd’s and PECO’s financial condition, results of operations or cash flows.

Certain PJM transmission owners, including ComEd and PECO, are subject to a rate design proceeding before the FERC. The issues in this proceeding involve the methodology used by PJM to charge customers for each PJM transmission owner’s regulated revenue requirement associated with its electric transmission facilities. On January 31, 2005, certain PJM transmission owners, including ComEd and PECO, made two separate filings in which the transmission owners jointly proposed to retain the present modified zonal rate design applicable within PJM and to implement three separate rate options for recovery of the revenue requirement associated with their new and existing facilities. As part of the group of PJM transmission owners, both ComEd and PECO proposed to retain the present rate design through January 2008, at which time the FERC could reevaluate the continuation of the rate design in PJM. The ultimate outcome of this proceeding is uncertain and may have a material adverse effect on ComEd’s and PECO’s financial condition, results of operations or cash flows.

ComEd. 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. On April 27, 2004, the FERC issued its order approving ComEd’s application to complete its integration

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into PJM, subject to certain stipulations including a provision to hold certain utilities in Michigan and Wisconsin harmless from the associated impacts for ComEd to join PJM. ComEd agreed to these stipulations and transferred functional control of its transmission assets to PJM and integrated fully into PJM’s energy market structures on May 1, 2004. In the fourth quarter of 2004, ComEd entered into settlement agreements with all such Michigan and Wisconsin utilities requiring a total payment of approximately $4 million by ComEd. FERC has approved these agreements and payment is expected to be made in the first quarter of 2005.

On November 10, 2003, the FERC issued an order allowing ComEd to put into effect, 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 have a significant effect on operating revenues until after December 31, 2006. During the third quarter of 2004, a settlement agreement was reached which was approved by the FERC during the fourth quarter of 2004, which established new rates that became effective May 1, 2004.

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. 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.

PECO’s gas customers have the right to choose their gas suppliers or to purchase their gas supply from PECO at cost. Approximately 32% of PECO’s current total yearly throughput is provided by gas suppliers other than PECO. Gas transportation service provided to customers by PECO 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 eight years. These purchases are delivered under several long-term firm transportation contracts. PECO’s aggregate annual firm supply under these firm transportation contracts is 47.7 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 29% of PECO’s 2004-2005 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 2005:

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Approximately 50% of ComEd’s and 65% of PECO’s 2005 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 and the competitive retail sales business of Exelon Energy Company.

At December 31, 2004, Generation owned generation assets with a net capacity of 25,756 MWs, including 16,751 MWs of nuclear capacity. Generation controls another 8,701 MWs of capacity through long-term contracts.

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. In addition, Power Team markets energy in the wholesale bilateral and spot markets.

Exelon Energy Company became part of Generation effective as of January 1, 2004. Exelon Energy provides retail electric and gas services as an unregulated retail energy supplier in Illinois, Michigan and Ohio. Exelon Energy’s 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 service customers with higher volumes so as to manage costs.

Generating Resources

At December 31, 2004, the generating resources of Generation consisted of the following:

The owned generating resources of Generation are located in the Mid-Atlantic region (approximately 45% of capacity), the Midwest region (approximately 43% of capacity), the Southern

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region (approximately 10%), and the Northeast region (approximately 2% of capacity). The 8,701 MWs of capacity that Generation controls through long-term contracts are in the Midwest, Southeast and South Central regions.

In December 2003, Generation purchased British Energy plc’s (British Energy) 50% interest in AmerGen Energy Company, LLC (AmerGen), making AmerGen a wholly owned subsidiary of Generation. The final purchase price was $267 million after working capital adjustments.

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. On September 29, 2004, Generation exercised its call option and entered into an agreement to acquire Reservoir’s 50% interest in Sithe and, on November 1, 2004, Generation entered into an agreement to sell Sithe to Dynegy Inc. The acquisition of Reservoir’s 50% interest in Sithe and the subsequent sale of 100% of Sithe to Dynegy occurred on January 31, 2005. The sale did not include Sithe International Inc. (Sithe International), which was sold to a subsidiary of Generation on October 13, 2004. Sithe International, through its subsidiaries, has 49.5% interests in two Mexican business trusts that own the TEG and TEP power stations, two 230 MW petcoke-fired generating facilities in Tamuín, Mexico. Effective January 26, 2005, Sithe International’s name was changed to Tamuin International Inc. See further discussion of these transactions in Notes 3 and 25 of Exelon’s Notes to Consolidated Financial Statements.

On May 25, 2004, Exelon and Generation completed the sale, transfer and assignment of ownership of their indirect wholly owned subsidiary Boston Generating, LLC (Boston Generating), which owns the companies that own Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities, to a special purpose entity owned by the lenders under Boston Generating’s $1.25 billion credit facility. Responsibility for plant operations and power marketing activities were transferred to the lenders’ special purpose entity and its contractors on September 1, 2004. See Note 2 of Exelon’s Notes to Consolidated Financial Statements for additional information regarding the sale of Boston Generating.

Nuclear Facilities

Generation has ownership interests in eleven nuclear generating stations currently in service, consisting of 19 units with 16,751 MW of capacity. For additional information, see ITEM 2. Properties. Generation’s nuclear generating stations are operated by Generation, with the exception of the two units at the Salem Generating Station (Salem), which are operated by PSEG Nuclear, LLC, an indirect, wholly owned subsidiary of PSEG. AmerGen operates the Clinton Nuclear Power Station, Three Mile Island (TMI) Unit 1 and Oyster Creek Nuclear Generating Station facilities.

Effective January 17, 2005, through an Operating Services Contract (OSC), Generation began overseeing daily plant operations at Salem and Hope Creek nuclear generating stations. Hope Creek is a PSEG wholly owned nuclear generating station. Under the OSC, PSEG Nuclear, LLC will continue as the license holder with exclusive legal authority to operate and maintain the plants, will retain responsibility for management oversight and will have full authority with respect to the marketing of its share of the output from the facilities.

In 2004, over 67% of Generation’s electric supply was generated from the nuclear generating facilities. During 2004 and 2003, the nuclear generating facilities operated by Generation operated at weighted average capacity factors of 93.5% and 93.4%, respectively.

Licenses. Generation has 40-year operating licenses from the NRC for each of its nuclear units and has received 20-year operating license renewals for the Peach Bottom Units 2 and 3, Dresden

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Units 2 and 3, and the Quad Cities Units. In December 2004, the NRC issued an order that will permit Oyster Creek to operate beyond its license expiration in April 2009 if the NRC has not completed reviewing the application for renewal. The application for Oyster Creek’s license renewal is expected to be filed by August 2005 in order to comply with this agreement. Generation is currently evaluating the other nuclear units for possible license renewal. The operating license renewal process takes approximately four to five years from the commencement of the project until completion of the NRC’s review. The NRC review process takes approximately two years from the docketing of an application. Each requested license renewal is expected to be for 20 years beyond the current license expiration. Depreciation provisions are based on the estimated useful lives of the stations, which assume the renewal of the operating licenses for all of Generation’s operating nuclear generating stations.

In 2004, Generation joined a consortium of eleven companies, NuStart Energy Development, LLC, which was formed for the purpose of seeking a license to build a new nuclear facility under the NRC’s new permitting process.

The following table summarizes the current operating license expiration dates for Generation’s nuclear facilities in service:

Regulation of Nuclear Power Generation. 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 and 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.

NRC reactor oversight results for the fourth quarter of 2004 indicate that the performance indicators for the nuclear plants operated by Generation are all in the highest performance band.

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Nuclear Waste Disposal. There are no facilities for the reprocessing or permanent disposal of spent nuclear fuel (SNF) currently in operation in the United States, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by nuclear 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, 2004, Generation had 43,156 SNF assemblies (10,360 tons) stored on site in SNF pools or dry cask storage. On-site dry cask storage in concert with on-site storage pools will be 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 development of a repository 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 Contracts) to provide for disposal of SNF from its nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation pays the DOE one mill ($.001) per kWh of net nuclear generation for the cost of SNF disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts 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 2012. 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. See Note 14 of Exelon’s Notes to Consolidated Financial Statements for additional information regarding spent fuel storage claims and issues.

During the third quarter of 2004, Exelon and the U.S. Department of Justice, in close consultation with the DOE, reached a settlement of a suit originally commenced by ComEd in 1998. Under the settlement, the government will reimburse Exelon for costs associated with storage of spent fuel at Generation’s nuclear stations pending DOE’s fulfilment of its obligations to take possession of SNF. Under the settlement agreement, Generation received $80 million in gross reimbursements for storage

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costs already incurred ($53 million net, after considering amounts due from Exelon to co-owners of certain nuclear stations), with additional amounts to be reimbursed annually for future costs. In all cases, reimbursements will be made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF.

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to pay the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, just prior to the first delivery of SNF to the DOE. As of December 31, 2004, the unfunded liability for the one-time fee with interest (which has been assumed by Generation) was $878 million. Interest accrues at the 13-week Treasury Rate, which was 1.987% at December 31, 2004. The outstanding one-time fee obligation for the Oyster Creek and TMI units remains with the former owner. The Clinton unit has no outstanding obligation.

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

Generation has temporary on-site storage capacity at its nuclear generation stations for limited amounts of LLRW and has been shipping its LLRW to 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 $26 million in 2004.

Nuclear Insurance. The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. As of December 31, 2004, the current limit was $10.76 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 $10.46 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. The maximum assessment for all nuclear operators per reactor per incident (including a 5% surcharge) is $100.6 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 by the expiration of the Price-Anderson Act. Existing commercial

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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. However, new licenses are not covered under the Price-Anderson Act and any new plant initiatives would need to address this exposure.

See “Nuclear Insurance” within Note 16 of Generation’s Notes to Consolidated Financial Statements for a description of nuclear-related insurance coverage.

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. As more fully described below, both ComEd and PECO are currently collecting amounts from ratepayers, which are ultimately remitted to the trust funds maintained by Generation that will be used to decommission nuclear facilities. The AmerGen facilities are not covered by the ComEd, PECO or any other rate recovery of decommissioning funding from customers. Decommissioning expenditures are expected to occur primarily after the plants are retired. Based on current operating licenses and anticipated license renewals, decommissioning expenditures for plants in operation are currently estimated to begin in 2029.

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 PPA between ComEd and Generation. Under the ICC order, ComEd was permitted to recover $73 million per year from customers for decommissioning for the years 2001 through 2004. In 2005 and 2006, ComEd is permitted to recover up to $73 million annually, depending upon the portion of the output of the former ComEd nuclear stations that ComEd purchases from Generation. Because ComEd is not expected to take all of the output of these stations, actual collections are expected to be less than $73 million annually in 2005 and 2006. Under the ICC order, subsequent to 2006, there will be no further recoveries though rates 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.

Nuclear decommissioning costs associated with the nuclear generating stations formerly owned by PECO continue to be recovered currently through rates charged by PECO to customers. Amounts recovered, currently $33 million per year, are remitted to Generation as allowed by the PUC.

Generation believes that the amounts currently being collected from ComEd and PECO, coupled with Generation’s nuclear decommissioning trust funds and the expected investment earnings thereon will be sufficient to fully fund Generation’s decommissioning obligations. AmerGen maintains decommissioning trust funds for each of its plants in accordance with NRC regulations. Generation believes that amounts in these trust funds, including expected investment earnings thereon, will be sufficient to fully fund AmerGen’s decommissioning obligations.

See Critical Accounting Policies and Estimates within ITEM 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operation—Generation for a further discussion of nuclear decommissioning.

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Zion, a two-unit nuclear generation station, Peach Bottom Unit 1 and Dresden Unit 1 have permanently ceased power generation. SNF at Zion and Dresden Unit 1 is currently being stored in on-site storage pools and dry cask storage, respectively, until a permanent repository under the NWPA is completed. All of Peach Bottom Unit 1’s SNF has been moved off site. Generation has recorded a liability totaling $762 million at December 31, 2004, which represents the estimated cost of decommissioning Zion, Peach Bottom Unit 1 and Dresden Unit 1 in current year dollars. Certain decommissioning costs are currently being incurred; however, the majority of decommissioning expenditures are expected to occur primarily after 2013, 2033 and 2030 for Zion, Peach Bottom Unit 1 and Dresden Unit 1, respectively.

Fossil and Hydroelectric Facilities

Generation operates various fossil and hydroelectric facilities and maintains ownership interest in several other facilities such as La Porte, Keystone, Conemaugh and Wyman, which are operated by third parties. In 2004, approximately 8% of Generation’s electric supply 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. For additional information regarding Generation’s electric generating facilities, see ITEM 2. Properties—Generation.

Licenses. Fossil generation plants are generally not licensed and, therefore, the decision on when to retire plants is, fundamentally, a commercial 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 renewals of 40 years for the Muddy Run and Conowingo plants, but the duration of any license renewal will depend on then-current policies at the FERC. The processing of a renewal to a hydroelectric license generally takes at least eight years.

Insurance. Generation does not purchase business interruption insurance for its wholly owned fossil and hydroelectric operations. For its other types of insured losses, Generation is self-insured to the extent that losses are within the policy deductible or 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 and cash flows. For information regarding property insurance, see ITEM 2. Properties—Generation.

Long-Term Contracts

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

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Federal Power Act

The Federal Power Act gives the FERC exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to the FERC’s jurisdiction are required to file rate schedules with the FERC with respect to wholesale sales and transmission of electricity. Transmission 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 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 power 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 subsequently determined that Generation or any of its affiliates exercised or has the ability to exercise market power. The FERC is also authorized to order refunds if it finds that the market-based rates are not just and reasonable.

In December 1999, 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 wholesale markets and the elimination or reduction of transmission charges imposed by successive transmission systems when wholesale generators cross several transmission systems to deliver capacity. Order No. 2000 and the FERC’s effort to promote RTOs throughout the states have generated substantial opposition by some state regulators and other governmental bodies. In addition, efforts to develop a RTO have been abandoned in certain regions.

PJM has been approved as a RTO, as has the Midwest ISO. ISO New England, the system operator for New England where Generation also owns facilities, was approved as a RTO on February 2, 2005.

Exelon supports the development of RTOs and implementation of standard market protocols but cannot predict their success or whether they will lead to the development of the envisioned large, successful wholesale markets. The FERC issued a final rule establishing standardized generator interconnection policies and procedures. Under this interconnection policy generators will benefit from not having to deal on a case-by-case basis with different and sometimes inconsistent requirements of different transmission providers.

The FERC recently announced new market power tests for suppliers to qualify to sell power at market-based rates. These new tests, the market share test and the pivotal supplier test, must both be passed by Generation, or market power mitigation must be imposed for Generation to continue to make sales of capacity and energy in the wholesale market at market based rates. Generation filed its analysis of the application of the tests on September 27, 2004, which proposed that Generation passed the market power screens. The FERC allows the relevant geographic market to include a RTO’s footprint, and Generation used an expanded PJM footprint as the relevant market. Because ComEd and PECO, which purchase most of Generation’s power, are members of PJM, Generation, for the most part, is selling into the PJM market. On January 5, 2005, the FERC issued a deficiency letter to Generation requesting a response to twelve separate questions relating to Generation’s filing. On January 26, 2005, Generation filed an initial response to the deficiency letter, answering certain questions and requesting until February 14, 2005 to complete the response to the deficiency letter. The FERC continues to process Generation’s application and market power analysis, as well as other applicants’ filings. Management expects that Generation will eventually pass the market power

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screens; however, there is no certainty as to what final determination will be made by the FERC in regard to Generation’s filing and the filings of other applicants.

Currently, a significant portion of Generation’s capacity is located within the PJM RTO area. If the FERC were to suspend Generation’s market-based rate authority, Generation would be required to supply and implement a plan for mitigation of market power. FERC’s default mitigation would require Generation 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 2004 and estimated for 2005:

The fuel costs for nuclear generation are substantially less than for fossil-fuel generation. Consequently, nuclear generation is generally the most cost-effective way for Generation to meet its commitment to supply the requirements of ComEd and PECO, some of Exelon Energy’s requirements, 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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Natural gas requirements for operating stations are 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 so that in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable market pricing.

Generation uses financial instruments to mitigate price risk associated with commodity price exposures. Generation also hedges forward price risk with both over-the-counter and exchange-traded instruments.

Power Team

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. 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 has also purchased transmission service to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery 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 2005 for its energy marketing portfolio is approximately 90%. This hedge ratio represents the percentage of forecasted aggregate annual generation supply that is committed to firm sales, including sales to Energy Delivery’s retail load. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand and volatility. During peak periods, the amount hedged declines to assure Generation’s commitment to meet Energy Delivery’s demand, for which the peak demand is during the summer. For the portion of generation supply that is unhedged, fluctuations in market price of energy will cause volatility in Generation’s results of operations.

Power Team also uses financial and commodity contracts for proprietary trading purposes but this activity accounts for only a small portion of Power Team’s efforts. 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.

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At December 31, 2004, Generation’s long-term commitments, relating to the purchase and sale of energy, capacity and transmission rights from and to unaffiliated utilities and others were as follows:

In connection with the 2001 corporate restructuring, Generation entered into a PPA, as amended, with ComEd under which Generation has agreed to supply all of ComEd’s load requirements through 2006. Under the ComEd PPA, prices for energy vary depending upon the time of day and month of delivery. Subsequent to 2006, ComEd expects to procure all of its supply from market sources, which could include Generation. Additionally, 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. Subsequent to 2010, PECO expects to procure all of its supply from market sources, which could include Generation.

When AmerGen acquired Clinton Nuclear Power Station (Clinton), AmerGen entered into a power sales agreement with the seller, Illinois Power Company (Illinois Power). The agreement with Illinois Power was for 68.8% of Clinton’s output for a term that expired on December 31, 2004. Generation has subsequently entered into a separate agreement with Illinois Power to provide fixed quantities of power under a power sales agreement over future periods beginning January 1, 2005. This agreement is included in the commitment table presented above.

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 2005 are as follows:

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Enterprises

During 2004 and 2003, Enterprises exited a significant number of businesses and investments, as described below. As of December 31, 2004, Enterprises consisted primarily of the remaining electrical contracting business of F&M Holdings, LLC. Enterprises is continuing to pursue opportunities to sell its remaining businesses.

Exelon Energy Company. Effective January 1, 2004, Enterprises competitive retail sales business, Exelon Energy Company, was transferred to Generation.

InfraSource, Inc. On September 24, 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource, Inc. for cash proceeds of approximately $175 million, net of transaction costs and cash transferred to the buyer upon sale plus a $30 million subordinated note. Enterprises recorded a net pre-tax loss and minority interest of $4 million associated with the sale and goodwill impairment charge in 2003.

Exelon Services, Inc. During 2004, Enterprises disposed of or wound down all of the operating businesses of Exelon Services, Inc. (Exelon Services), including Exelon Solutions, the mechanical services businesses and the Integrated Technology Group. Total expected proceeds and the pre-tax net gain on sale recorded in 2004 related to the disposition of the Exelon Services businesses were $61 million and $9 million, respectively.

Exelon Thermal Holdings, Inc. On June 30, 2004, Enterprises sold its Chicago businesses of Exelon Thermal Holdings, Inc. (Thermal) for net cash proceeds of $134 million and expected proceeds of $2 million from a working capital settlement, resulting in a pre-tax gain of $36 million, net of debt prepayment penalties. On September 29, 2004, Enterprises closed on the sale of ETT Nevada, Inc., the holding company for its investment in Northwind Aladdin, LLC, for a net cash outflow of $1 million, subject to working capital adjustments. Enterprises recorded a pre-tax loss of $3 million related to the disposition. On October 28, 2004, Northwind Windsor, of which Enterprises owns a 50% interest, sold substantially all of its assets, providing Enterprises with cash proceeds of $8 million, resulting in a pre-tax gain of $2 million.

PECO TelCove. On June 30, 2004, Enterprises sold its investment in PECO TelCove, a communications joint venture, along with certain telecommunications assets, for proceeds of $49 million, resulting in a pre-tax gain of $9 million.

Exelon Capital Partners Holdings, LLC. During 2004, Enterprises sold its direct investments and investments in three of its four venture capital funds.

Employees

As of December 31, 2004, Exelon and its subsidiaries had approximately 17,300 employees in the following companies:

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Approximately 5,500 employees, including 3,800 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 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 September 30, 2007. The CBA for ComEd and BSC expires on September 30, 2008. The Clinton, Oyster Creek and TMI CBAs expire on December 15, 2005, January 31, 2006 and February 28, 2009, respectively. Exelon Power, an operating unit of Generation, has negotiated and ratified its first agreement with IBEW Local 614. The agreement expires on January 31, 2008 and covers approximately 200 employees.

In addition to IBEW Local 15, IBEW Local 614 and the four IBEW locals covering the AmerGen facilities, approximately 50 Generation employees are represented by the Utility Workers Union of America.

During 2004, two elections were held at PECO which resulted in union representation for approximately 1,100 employees in the Philadelphia service territory. PECO and IBEW Local 614 will begin negotiations for an initial agreement in the first quarter of 2005.

The employees of the Limerick and Peach Bottom nuclear stations are not currently covered by a CBA. IBEW 614 has filed a petition with the National Labor Relations Board to hold a certification election at these sites. The election will be held in the first quarter of 2005.

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 United States Environmental Protection Agency (EPA) administers certain Federal statutes relating to such matters, as do various interstate and local agencies. 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.

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 renewals of such permits while operating under an administrative extension.

In July 2004, the EPA issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. This rule establishes national requirements for reducing the adverse environmental impacts from the entrainment and impingement of aquatic organisms at existing power plants. The rule identifies particular standards of performance with respect to entrainment and impingement and requires each facility to monitor and validate this performance in future years. The requirements will be

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implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems are potentially most affected. Those facilities are Clinton, Cromby, Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, New Boston, Oyster Creek, Peach Bottom, Quad Cities and Salem. Generation is currently evaluating compliance options at its affected plants. At this time, Generation cannot estimate the effect that compliance with the Phase II rule requirements will have on the operation of its generating facilities and its future results of operations, financial condition and cash flows. There are many factors to be considered and evaluated to determine how Generation will comply with the Phase II rule requirements and the extent to which such compliance may result in financial and operational impacts. The considerations and evaluations include, but are not limited to obtaining clarifying interpretations of the requirements from state regulators, resolving outstanding litigation proceedings concerning the requirements, completing studies to establish biological baselines for each facility, and performing environmental and economic cost benefit evaluation of the potential compliance alternatives in accordance with the requirements. 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.

In June 2001, the New Jersey Department of Environmental Protection (NJDEP) issued a renewed National Pollutant Discharge Elimination System permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. An application for renewal of that permit, including a demonstration of compliance with the requirements of the recently published Federal Water Pollution Control Act Section 316(b) regulations, must be submitted to NJDEP by February 2, 2006 unless NJDEP grants additional time to collect information to comply with the new regulations. NJDEP advised PSEG in a letter dated July 12, 2004 that it strongly recommends reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG has not made a determination regarding how it will demonstrate compliance with the Section 316(b) regulations. If application of the Section 316(b) regulations requires the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, the retrofit and an resulting cost of interim replacement power could result in material costs of compliance to the owners of the facility.

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

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undertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third party.

By notice issued in November 1986, the EPA notified over 800 entities, including ComEd and PECO, that they may be PRPs under CERCLA with respect to releases of radioactive and/or toxic substances from the Maxey Flats disposal site, a LLRW disposal site near Moorehead, Kentucky, where ComEd and PECO 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 (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 $14 million to $17 million. Significant progress has been made in settlement discussions between the EPA, the PRP group and the former owners and operators of the site. Exelon now believes that it is probable that the parties will agree to a settlement within the remedial range and that Exelon’s share of such settlement will be approximately 30%. This amount does not include Exelon’s share of the PRP group’s future legal and technical expenses, which are not expected to be material. The settlement amount will also not include any damages for natural resource damages that the EPA or state environmental agencies may seek to obtain in the future, and at this time PECO cannot predict with reasonable certainty the likelihood that such damages will be sought or the amount of any such damages.

Cotter Corporation

The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700

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tons of leached barium sulfate at the site. Cotter, along with three other companies identified by the EPA as PRPs, has submitted a draft feasibility study addressing options for remediation of the site. The PRPs are also engaged in discussions with the State of Missouri and the EPA. The estimated costs of the anticipated remediation strategy for the site ranges up to $22 million. Once a remedy is selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for liability from the West Lake Landfill and the litigation described under ITEM 3. Litigation—Generation. In connection with Exelon’s 2001 corporate restructuring, the responsibility to indemnify Cotter for any liability related to these matters was transferred by ComEd to Generation.

MGP Sites

MGPs manufactured gas in Illinois and Pennsylvania from approximately 1850 to 1950. ComEd and PECO generally did not operate MGPs as corporate entities but did, however, acquire MGP sites as part of the absorption of smaller utilities. Approximately half of the ComEd 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 Environmental Protection Agency has approved the clean-up of four sites. Similarly, PECO has identified 27 sites where former MGP activities may have resulted in site contamination. Of these 27 sites, the PDEP has approved the clean-up of nine 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 reviewed periodically with the regulatory authorities. At December 31, 2004, ComEd and PECO had accrued $55 million (discounted) and $41 million (discounted), respectively, for investigation and remediation of these MGP sites that currently can be reasonably estimated. 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 settled in principle with all of the insurers in the insurance litigation lawsuit for remediation costs associated with former MGP sites. PECO expects to finalize all settlement agreements in the first quarter of 2005. ComEd is in settlement negotiations with one insurance carrier for remediation costs associated with 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 (CAA) 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

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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 started May 31, 2004. Texas is not covered by the EPA’s ozone transport regulations. The EPA’s ozone transport regulations currently require 19 eastern states to reduce summertime NO_x emissions.

Generation 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. 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 Handley and Mountain Creek 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 were required to comply with the Emission Banking and Trading of Allowances (EBTA) program established by the State of Texas 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, as of June 30, 2004, had installed Selective Catalytic Reduction technology on Handley Units 3, 4 and 5, as well as Mountain Creek Unit 8. Additionally, Induced Flue Gas Recirculation Technology was installed on Mountain Creek Unit 6. Induced Flue Gas Recirculation Technology will be installed on Mountain Creek Unit 7 in 2005 prior to the DFW NO_x SIP program being fully implemented on May 1, 2005. This will complete all NO_x control technology upgrades planned for the DFW plants.

Many other provisions of the Amendments affect activities of Exelon’s businesses, primarily Generation. The Amendments establish stringent control measures for geographical regions that 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 issued several new proposed rulemakings during 2004 to reduce powerplant emissions of SO₂, NO_x and mercury. In its proposed “Clean Air Interstate Rule (CAIR)” rulemaking, the EPA has proposed NO_x and SO₂ emission caps in 29 eastern states, to be phased-in during 2010 and 2015, that are substantially below current industry emission levels. The CAIR rule is intended to support regional attainment of Federal ground-level ozone (eight-hour) and fine particulate (PM2.5) NAAQS. In a separate hazardous air pollutant-related rulemaking, the EPA has also proposed several options to regulate mercury emissions from coal-fired power plants under either

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Section 112 or Section 111 of the CAA. Regulation of nickel emissions from oil-fired power plants is also contemplated as part of this latter proposed rulemaking. 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 Generation’s operations and cash flows.

Global Climate Change

The United States is currently not a party to the United Nations’ Kyoto Protocol (Protocol) that became effective for signatories on February 16, 2005. The Protocol process generally requires developed countries to cap greenhouse gas (GHG) emissions at certain levels during the 2008-2012 time period. Although it is not a signatory to the Protocol, the United States may adopt a national, mandatory GHG program at some point in the future. At this time, Exelon is unable to predict the potential impacts of any future mandatory governmental GHG legislative or regulatory requirements on its businesses.

In the absence of a mandatory national program, Exelon has joined the U.S. EPA Climate Leaders Partnership (Climate Leader). As a Climate Leader partner, Exelon is conducting an annual inventory of its GHG emissions, developing a GHG emission reduction goal, and annually reporting its GHG emissions and progress toward achieving GHG reductions.

As an integrated electric and gas utility, approximately 90% of Generation’s GHG emissions result from the combustion of fossil fuels to generate electricity, with carbon dioxide (CO₂) representing the largest quantity of GHG emitted. The majority of Generation’s owned generation is comprised of nuclear and hydro-electric assets that have negligible GHG emissions compared to fossil-based electric generation alternatives. By virtue of Generation’s significant investment in these low carbon intensity assets, Generation’s owned-generation portfolio CO₂ emission intensity, or rate of CO₂ emitted per kilowatt-hour of electricity generated, is among the lowest in the industry.

Renewable and Alternative Energy Portfolio Standards

Approximately 17 states have adopted some form of renewable portfolio standard (RPS) legislation. On November 30, 2004, Pennsylvania adopted Act 213, the Alternative Energy Portfolio Standards Act of 2004 (AEPS Act). The AEPS Act mandates that two years after its effective date (February 28, 2005) at least 1.5% of electric energy sold by an electric distribution company or electric generation supplier to Pennsylvania retail electric customers must come from Tier I alternative energy resources. The Tier I requirement escalates to 8.0% by the 15^th year after the effective date of the AEPS Act. The AEPS Act also establishes a Tier II requirement of 4.2% for years one through four. This requirement grows to 10.0% by the 15^th year.

Tier I resources include: solar photovoltaic energy, wind power, low-impact hydro, geothermal energy, biologically derived methane gas, fuel cells, biomass energy and coal mine methane. A small percentage of the Tier I requirements must be met specifically by solar photovoltaic technologies (starting at 0.0013% in year 1 and escalating to 0.25% by year 10). Tier II resources include: waste coal, distributed generation systems, demand side management, large-scale hydropower, municipal solid waste and several other technologies.

The AEPS Act provides an exemption for electric distribution companies that have not reached the end of their cost recovery period during which competitive transition charges or intangible transition charges are being recovered. At the conclusion of the electric distribution company’s cost recovery period, this exemption no longer applies and compliance by the electric distribution company is required at the percentages in effect at that time. PECO’s cost recovery period expires December 31, 2010.

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In the first year after the end of an electric distribution company’s cost recovery period, the AEPS Act provides for cost recovery on a full and current basis pursuant to an automatic energy adjustment charge as a cost of generation supply. The banking of credits from voluntary sales of Tier I and Tier II sources sold by electric distribution companies prior to the expiration of their specific cost recovery periods is also allowed under the AEPS Act. Voluntary sales under the AEPS Act are deferred as a regulatory asset by the electric distribution company and are fully recoverable at the end of the cost recovery period, also pursuant to an automatic energy adjustment clause as a cost of generation supply.

The PUC is required to establish regulations to implement the AEPS Act. These regulations will be material to a complete assessment of the effects of the AEPS Act on PECO. While Generation is not directly affected from a compliance perspective, increased deployment of renewable and alternative energy resources within the regional power pool resulting from the AEPS Act will have some influence on regional energy markets.

In addition to the AEPS Act, similar legislation has been, and may be, considered by the United States Congress. Also, states that currently do not have RPS requirements, including Illinois, may determine to adopt such legislation in the future.

Exelon is currently evaluating the potential impacts of RPS legislation on its businesses.

Costs

At December 31, 2004, ComEd, PECO and Generation had accrued $61 million, $47 million and $16 million, respectively, for various environmental investigation and remediation. These costs include approximately $55 million at ComEd and $41 million at PECO for former MGP sites as described above. ComEd, PECO and Generation 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, PECO and Generation, environmental agencies or others, or whether all such costs will be recoverable through rates or from third parties.

The budgets for expenditures in 2005 at ComEd, PECO and Generation for compliance with environmental requirements total approximately $8 million, $8 million and $7 million, respectively. In addition, ComEd, PECO and Generation may be required to make significant additional expenditures not presently determinable.

Security

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. 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 maintain critical operations.

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.

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Other Subsidiaries of ComEd and PECO with Publicly Held Securities

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 LLC, a special purpose Delaware limited liability company, was organized on July 21, 1998. ComEd Funding Trust was created for the sole purpose of issuing transitional funding notes to securitize intangible transition property granted to ComEd Funding LLC, a ComEd affiliate, by an ICC order issued July 21, 1998. On December 16, 1998, ComEd Funding Trust issued $3.4 billion of transitional funding notes, the proceeds of which were used to purchase the intangible transition property held by ComEd Funding LLC. ComEd Funding LLC transferred the proceeds to ComEd where they were used, among other things, to repurchase outstanding debt and equity securities of ComEd. The transitional funding notes are solely obligations of ComEd Funding Trust and are secured by the intangible transition property, which represents the right to receive instrument funding charges collected from ComEd’s customers. The instrument funding charges represent a non-bypassable, usage-based, per kWh charge on designated consumers of electricity.

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 and selling preferred and common securities. On January 24, 1997, ComEd Financing Trust II issued $150 million of trust preferred securities, carrying an annual distribution rate of 8.50%, which are mandatorily redeemable on January 15, 2027. ComEd is the sole owner of all of the common securities of ComEd Financing Trust II. 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. ComEd is the sole owner of all of the common securities of ComEd Financing Trust III. 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.

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 (PECC), is the sole general partner of PECO Energy Capital, L.P., a Delaware limited partnership (PEC L.P.). PEC L.P. 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 PEC L.P. The only revenues of PEC L.P. are interest on the Subordinated Debentures. All of the operating expenses of PEC L.P. are paid by PECC. As of

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December 31, 2004, PEC L.P. held $81 million aggregate principal amount of the Subordinated Debentures.

PECO Energy Capital Trust III (PECO Trust III), a Delaware statutory trust, was formed by PECO in April 1998. PECO Trust III was created solely for the purpose of issuing $78 million trust receipts (Trust III Receipts) each representing a 7.38% Cumulative Preferred Security, Series D (Series D Preferred Securities) of PEC L.P. PEC L.P. is the sponsor of PECO Trust III. As of December 31, 2004, PECO Trust III had outstanding 78,105 Trust III Receipts. At December 31, 2004, the assets of PECO Trust III consisted solely of 78,105 Series D Preferred Securities with an aggregate stated liquidation preference of $81 million.

PECO Energy Capital Trust IV (PECO Trust IV), a Delaware statutory trust, was formed by PECO in May 2003. PECO Trust IV was created solely for the purpose of issuing and selling preferred and common securities. On June 17, 2003, PECO Trust IV issued $100 million of trust preferred securities, carrying an annual distribution rate of 5.75%, which are mandatorily redeemable on June 15, 2033. PECO is the sole owner of all of the common securities of the PECO Trust IV. The sole assets of PECO Trust IV are $103 million principal amount of 5.75% subordinated debentures issued by PECO.

The financing trusts discussed above were deconsolidated from the financial statements of Exelon, ComEd and PECO in 2003. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for additional information.

Executive Officers of the Registrants at December 31, 2004

Exelon

ComEd

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PECO

Generation

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; and Chairman, President and Chief Executive Officer of ComEd and Unicom. Mr. Rowe was elected as an officer of Exelon effective October 20, 2000.

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. Mr. Clark was elected as an officer of Exelon effective October 20, 2000.

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. Mr. McLean was elected as an officer of Exelon effective October 20, 2000.

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. Mr. Mehrberg was elected as an officer effective December 3, 2001.

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. Ms. Moler was elected as an officer effective October 20, 2000.

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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. Mr. Shapard was elected as an officer effective October 21, 2002.

Prior to his election to his listed position, Mr. Skolds was Senior Vice President, Exelon, and President and Chief Nuclear Officer, Exelon Nuclear; and President and Chief Operating Officer of South Carolina Electric and Gas. Mr. Skolds was elected as an officer effective October 20, 2000.

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. Mr. Snodgrass was elected as an officer effective October 20, 2000.

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. Ms. Strobel was elected as an officer effective October 20, 2000.

Prior to his election to his listed position, Mr. Young was President of Exelon Power; Senior Vice President of Sierra Pacific Resources Corporation; President of Avalon Consulting; and Executive Vice President of Southern Generation. Mr. Young was elected as an officer effective March 3, 2003.

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; and Assistant Treasurer of Kmart Corporation. Mr. Hilzinger was elected as an officer effective April 15, 2002.

Prior to her election to her listed position, Ms. Gillis was Senior Vice President of Exelon; President of Business Services Company; Chief Financial Officer of Exelon; and Senior Vice President and Chief Financial Officer of Unicom Corporation. Ms. Gillis was elected as an officer effective October 20, 2000.

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. Mr. Mitchell was elected as an officer of Exelon effective October 20, 2000.

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. Mr. O’Brien was elected as an officer effective January 1, 2001.

Prior to his election to his listed position, Mr. Crane was Vice President for Exelon Nuclear; and Vice President for BWR Operations of ComEd. Mr. Crane was elected as an officer effective December 27, 2000.

Prior to his election to his listed position, Mr. Schiavoni was Vice President of Operations; and Vice President of Northeast Operations of Exelon Power. Mr. Schiavoni was elected as an officer effective September 8, 2003.

Prior to his election to his listed position, Mr. Veurink was a partner at Deloitte & Touche LLP. Mr. Veurink was elected as an officer effective January 5, 2004.

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Energy Delivery

The electric substations and a portion of the transmission rights of way are located on property owned by ComEd and PECO. 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 but without examination of underlying land titles, have been obtained.

Transmission and Distribution

Energy Delivery’s higher voltage electric transmission lines owned and in service at December 31, 2004 were as follows:

ComEd’s electric distribution system includes 43,700 circuit miles of overhead lines and 32,900 cable miles of underground lines. PECO’s electric distribution system includes 12,150 circuit miles of overhead lines and 15,389 cable miles of underground lines.

Gas

The following table sets forth PECO’s gas pipeline miles at December 31, 2004:

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.

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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. For its insured losses, ComEd and PECO are self-insured to the extent that any losses are within the policy deductible or 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.

Generation

The following table sets forth Generation’s owned net electric generating capacity by station at December 31, 2004. The table does not include properties held by equity method investments:

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

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

ComEd

Retail Rate Law. In 1996, three developers of non-utility generating facilities filed litigation against various Illinois officials claiming that the enforcement against those facilities of an amendment to Illinois law removing the entitlement of those facilities to state-subsidized payments for electricity sold to ComEd after March 15, 1996 violated their rights under Federal and state constitutions. The developers also filed suit against ComEd for a declaratory judgment that their rights under their contracts with ComEd were not affected by the amendment and for breach of contract. On November 25, 2002, the court granted the developers’ motions for summary judgment. The judge also entered a permanent injunction enjoining ComEd from refusing to pay the retail rate on the grounds of the amendment and Illinois from denying ComEd a tax credit on account of such purchases. On March 9, 2004, the Illinois Appellate Court reversed the trial court. The Appellate Court held that the 1996 law does apply to the developers’ facilities and, therefore, they are not entitled to subsidized payments. The Court expressly ruled that the breach of contract claims against ComEd are dismissed with prejudice. Two of the developers sought review of the Appellate Court’s decision by the Illinois Supreme Court. On May 26, 2004, the Supreme Court declined to hear the earlier-filed of the two appeals. On October 6, 2004, the Supreme Court declined to hear the final appeal. The time for further appeals has now passed. Related claims remain pending in the trial court.

PECO and Generation

Real Estate Tax Appeals. PECO and Generation each have been challenging real estate taxes assessed on nuclear plants. PECO is involved in litigation in which it is contesting taxes assessed in 1997 under the Pennsylvania Public Utility Realty Tax Act of March 4, 1971, as amended (PURTA), and has appealed local real estate assessments for 1998 and 1999 on the Limerick Generating Station (Montgomery County, PA) (Limerick) and Peach Bottom Atomic Power Station (York County, PA) (Peach Bottom). Generation is involved in real estate tax appeals for 2000 through 2004, also regarding the valuation of its Limerick and Peach Bottom plants and Quad Cities Station (Rock Island County, IL), Three Mile Island Nuclear Station (Dauphin County, PA) and Oyster Creek Nuclear Generating Station (Forked River, NJ).

Generation

Cotter Corporation Litigation. During 1989 and 1991, actions were brought in Federal and state courts in Colorado against ComEd and its subsidiary, Cotter, seeking unspecified damages and injunctive relief based on allegations that Cotter permitted radioactive and other hazardous material to be released from its mill into areas owned or occupied by the plaintiffs, resulting in property damage and potential adverse health effects. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability incurred by Cotter as a result of these actions. In connection with Exelon’s 2001 corporate restructuring, the responsibility to indemnify Cotter for any liability related to these matters was transferred by ComEd to Generation.

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Several of the actions resulted in nominal jury verdicts or were settled or dismissed. One action resulted in an award for the plaintiffs of a more substantial amount, but was reversed on April 22, 2003 by the Tenth Circuit Court of Appeals and remanded for retrial. An appeal by the plaintiffs to the United States Supreme Court was denied on November 10, 2003. In October 2004, a settlement of the claims of all Cotter plaintiffs was reached and approved by the Federal District Court in Colorado. This settlement amount approximated Generation’s reserve for this matter. Settlements with the two primary Cotter insurers were also concluded, under which they paid Generation approximately $20 million, which covered the amount previously reserved as well as certain other costs incurred by Generation related to this matter. Neither of these settlements affects the environmental liability associated with the West Lake Landfill. For additional information, see ITEM 1. Environmental Regulation.

General

Exelon, ComEd, PECO and Generation are involved in various other litigation matters that are being defended and handled in the ordinary course of business. Exelon, ComEd, PECO and Generation maintain accruals for such costs that are probable of being incurred and subject to reasonable estimation. The ultimate outcomes of such matters, as well as the matters discussed above, are uncertain and may have a material adverse effect on their respective financial condition, results of operations or cash flows.

Exelon, ComEd, PECO and Generation

None.

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PART II

(Dollars in million except per share data, unless otherwise noted)

Exelon

Exelon’s common stock is listed on the New York Stock Exchange. See Note 24 of Exelon’s Notes to Consolidated Financial Statements for the high and low sales prices, closing prices and dividends for Exelon’s common stock for 2004 and 2003 on a per share basis. As of January 31, 2005, there were 664,807,122 shares of common stock outstanding and approximately 166,575 shareholders of common stock of record.

On January 27, 2004, the Exelon Board of Directors approved a 2-for-1 stock split of Exelon’s common stock. The distribution date was May 5, 2004. The authorized common stock was increased from 600,000,000 shares with no par value to 1,200,000,000 shares with no par value. The share and per-share amounts related to Exelon included in this Form 10-K have been adjusted for all periods presented to reflect the stock split.

The attached table gives information on a monthly basis regarding purchases made by Exelon of its common stock.