10-K 1 c68219e10-k.txt ANNUAL REPORT UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ------------------- FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Name of Registrant; State of Incorporation; Address of IRS Employer Number Principal Executive Offices; and Telephone Number Identification Number ---------------- --------------------------------------------------------- ------------------------- 1-16169 EXELON CORPORATION 23-2990190 (a Pennsylvania corporation) 10 South Dearborn Street - 37th Floor P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-4321 1-1839 COMMONWEALTH EDISON COMPANY 36-0938600 (an Illinois corporation) 10 South Dearborn Street - 37th Floor P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-4321 1-1401 PECO ENERGY COMPANY 23-0970240 (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000

SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

Name of Each Exchange on Title of Each Class Which Registered ------------------------------------------------------------------------------ ----------------------------- EXELON CORPORATION: Common Stock, without par value New York, Chicago and Philadelphia COMMONWEALTH EDISON COMPANY: Company-Obligated Mandatorily Redeemable Preferred Securities of New York Subsidiary Trust Holding Solely Commonwealth Edison Company's 8.48% Subordinated Debt Securities and unconditionally guaranteed by Commonwealth Edison Company PECO ENERGY COMPANY: First and Refunding Mortgage Bonds: 6-3/8% Series due 2005, and 6-1/2% New York Series due 2003

i

Cumulative Preferred Stock, without par value: $4.68 Series, $4.40 New York Series, $4.30 Series and $3.80 Series Trust Receipts of PECO Energy Capital Trust II, each representing an New York 8.00% Cumulative Monthly Income Preferred Security, Series C, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company Trust Receipts of PECO Energy Capital Trust III, each representing a New York 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: COMMONWEALTH EDISON COMPANY: Common Stock Purchase Warrants, 1971 Warrants and Series B Warrants PECO ENERGY COMPANY: Cumulative Preferred Stock, without par value: $7.48 Series and $6.12 Series 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. [ ] The estimated aggregate market value of the voting and non-voting common equity held by nonaffiliates of each registrant as of March 1, 2002, was as follows:

Exelon Corporation Common Stock, without par value $15,839,570,208 Commonwealth Edison Company Common Stock, $12.50 par value No established market PECO Energy Company Common Stock, without par value None The number of shares outstanding of each registrant's common stock as of March 1, 2002 was as follows: Exelon Corporation Common Stock, without par value 321,419,850 Commonwealth Edison Company Common Stock, $12.50 par value 127,016,373 PECO Energy Company Common Stock, without par value 170,478,507

ii DOCUMENTS INCORPORATED BY REFERENCE: Portions of Exelon Corporation's Current Report on Form 8-K dated February 28, 2002 containing consolidated financial statements and related information for the year ended December 31, 2001, are incorporated by reference into Parts I, II and IV of this Annual Report on Form 10-K. Portions of Exelon Corporation's definitive Proxy Statement filed on March 13, 2002 relating to its annual meeting of shareholders, are incorporated by reference into Part III of this Annual Report on Form 10-K. Portions of Commonwealth Edison Company's definitive Information Statement to be filed prior to April 30, 2002, relating to its annual meeting of shareholders, are incorporated by reference into Part III of this Annual Report on Form 10-K. Portions of PECO Energy Company's definitive Information Statement to be filed prior to April 30, 2002, relating to its annual meeting of shareholders, are incorporated by reference into Part III of this Annual Report on Form 10-K. This combined Form 10-K is separately filed by Exelon Corporation, Commonwealth Edison Company and PECO Energy Company. Information contained herein relating to any individual registrant is filed by such registrant in its own behalf. Each registrant makes no representation as to information relating to the other registrants. iii TABLE OF CONTENTS

PAGE NO. -------- FORWARD LOOKING STATEMENTS 1 PART I ITEM 1. BUSINESS 2 General 2 Energy Delivery 3 Generation 11 Enterprises 26 Employees 27 Environmental Regulation 28 Other Subsidiaries of ComEd and PECO with Publicly Held Securities 32 Executive Officers of the Registrants 34 ITEM 2. PROPERTIES 36 ITEM 3. LEGAL PROCEEDINGS 39 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 42 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS 43 ITEM 6. SELECTED FINANCIAL DATA 44 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 47 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 81 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 84 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 145 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 146 ITEM 11. EXECUTIVE COMPENSATION 146 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 147 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 148 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K 149 SIGNATURES 166

iv FORWARD-LOOKING STATEMENTS Except for the historical information contained herein, certain of the matters discussed in this Report are forward-looking statements that are subject to risks and uncertainties. The factors that could cause actual results to differ materially include those discussed herein as well as those listed in ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Outlook and in ITEM 8. Financial Statements and Supplementary Data, Notes to Consolidated Financial Statements; Exelon - Note 20; ComEd - Note 16; and PECO Note 18 and other factors discussed in Exelon Corporation (Exelon), Commonwealth Edison Company (ComEd) and PECO Energy Company's (PECO) filings with the SEC. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this Report. Exelon, ComEd and PECO undertake no obligation to publicly release any revision to these forward-looking statements to reflect events or circumstances after the date of this Report. 1 PART I ITEM 1. BUSINESS. GENERAL Exelon Corporation (Exelon) was incorporated in Pennsylvania in February 1999. On October 20, 2000, Exelon became the parent corporation for each of Commonwealth Edison Company (ComEd) and PECO Energy Company (PECO) as a result of the completion of the transactions contemplated by an Agreement and Plan of Exchange and Merger, as amended, among PECO, Unicom Corporation (Unicom) and Exelon (Merger). The Merger was accounted for using the purchase method of accounting. During January 2001, Exelon undertook a restructuring to separate its generation and other competitive businesses from its regulated energy delivery business at ComEd and PECO. As part of the restructuring, the generation-related operations and assets and liabilities of ComEd were transferred to Exelon Generation Company, LLC (Generation). Also, as part of the restructuring, the non-regulated operations and related assets and liabilities of PECO, representing PECO's generation and enterprises business segments, were transferred to Generation and Exelon Enterprises Company, LLC (Enterprises), respectively. Additionally, certain operations and assets and liabilities of ComEd and PECO were transferred to Exelon Business Services Company (BSC). Exelon, through its subsidiaries, operates in three business segments: o Energy Delivery, consisting of the retail electricity distribution and transmission businesses of ComEd in northern Illinois and PECO in southeastern Pennsylvania and the natural gas distribution business of PECO in the Pennsylvania counties surrounding the City of Philadelphia. o Generation, consisting of electric generating facilities, energy marketing operations and equity interests in Sithe Energies, Inc. (Sithe) and AmerGen Energy Company, LLC (AmerGen). o Enterprises, consisting of competitive retail energy sales, energy and infrastructure services, communications and other investments weighted towards the communications, energy services and retail services industries. Exelon's principal executive offices are located at 10 South Dearborn Street, Chicago, Illinois 60603, and its telephone number is 312-394-4321. ComEd was organized in the State of Illinois in 1913 as a result of the merger of Cosmopolitan Electric Company into the original corporation named Commonwealth Edison Company, which was incorporated in 1907. ComEd's principal executive offices are located at 10 South Dearborn Street, Chicago, Illinois 60603 and its telephone number is 312-394-4321. PECO was incorporated in Pennsylvania in 1929. PECO's principal executive offices are located at 2301 Market Street, Philadelphia, Pennsylvania 19101-8699 and its telephone number is 215-841-4000. Exelon and various of its subsidiaries are subject to Federal and state regulation. Exelon is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). ComEd is a public utility under the Illinois Public Utilities Act subject to regulation by the Illinois Commerce Commission (ICC). PECO is a public utility under the Pennsylvania Public Utility Code subject to regulation by the Pennsylvania 2 Public Utility Commission (PUC). PECO, ComEd and Generation are electric utilities under the Federal Power Act subject to regulation by the Federal Energy Regulatory Commission (FERC). Specific operations of Exelon are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the United States Nuclear Regulatory Commission (NRC). As a registered holding company, Exelon and its subsidiaries are subject to a number of restrictions under PUHCA. These restrictions generally involve financing, investments and affiliate transactions. Under PUHCA, Exelon and its subsidiaries cannot issue debt or equity securities or guaranties without approval of the Securities and Exchange Commission (SEC) or in some circumstances in the case of ComEd and PECO, the ICC or the PUC, respectively. Exelon currently has SEC approval to issue up to an aggregate of $4 billion in common stock, preferred securities, long-term debt and short-term debt, and to issue up to $4.5 billion in guaranties. PUHCA also limits the businesses in which Exelon may engage and the investments that Exelon may make. With limited exceptions, Exelon may only engage in traditional electric and gas utility businesses and other businesses that are reasonably incidental or economically necessary or appropriate to the operations of the utility business. The exceptions include Exelon's ability to invest in exempt telecommunications companies, in exempt wholesale generating businesses and foreign utility companies (these investments are capped at $4 billion in the aggregate), in energy-related companies (as defined in SEC rules, and subject to a cap on these investments of 15% of Exelon's consolidated capitalization), and in other businesses, subject to SEC approval. In addition, PUHCA requires that all of a registered holding company's utility subsidiaries constitute a single system that can be operated in an efficient, coordinated manner. For additional information about restrictions on the payment of dividends and other effects of PUHCA on Exelon and its subsidiaries, see ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Exelon. ENERGY DELIVERY Energy Delivery consists of Exelon's regulated energy delivery operations conducted by ComEd and PECO. ComEd is engaged principally in the purchase, transmission, distribution and sale of electricity to a diverse base of residential, commercial, industrial and wholesale customers in northern Illinois. ComEd is a public utility under the Illinois Public Utilities Act. Consequently, ComEd is subject to regulation by the ICC as to rates and charges, issuance of most of its securities, service and facilities, classification of accounts, transactions with affiliated interests, as defined in the Illinois Public Utilities Act, and other matters. ComEd is also subject to regulation by FERC as to transmission rates and certain other aspects of its business, including interconnections and sales of transmission related assets. ComEd's retail service territory has an area of approximately 11,300 square miles and an estimated population of approximately 8 million as of December 31, 2001. The service territory includes the City of Chicago, an area of about 225 square miles with an estimated population of approximately 3 million. ComEd had approximately 3.6 million customers at December 31, 2001. 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 2002 to 2050 and subsequent years. 3 PECO is engaged principally in the purchase, transmission, distribution and sale of electricity to residential, commercial, industrial and wholesale customers and in the purchase, distribution and sale of natural gas to residential, commercial and industrial customers. PECO is a public utility under the Pennsylvania Public Utility Code. As a result, PECO is subject to regulation by the PUC as to electric distribution rates, retail gas rates, issuances of securities and certain other aspects of PECO's operations. PECO is also subject to regulation by FERC as to transmission rates and certain other aspects of its business, including interconnections and sales of transmission related assets. PECO's traditional retail service territory covers 2,107 square miles in southeastern Pennsylvania. PECO provides electric delivery service in an area of 1,972 square miles, with a population of approximately 3.8 million, including 1.5 million in the City of Philadelphia. Natural gas service is supplied in a 1,625 square mile area in southeastern Pennsylvania adjacent to Philadelphia, with a population of 2.3 million. PECO delivers electricity to approximately 1.5 million customers and natural gas to approximately 440,000 customers. PECO has the necessary franchise rights to furnish electric and gas service in the various municipalities or territories in which it now supplies such services. PECO's franchise rights, which are generally nonexclusive rights, consist of charter rights and certificates of public convenience issued by the PUC and/or "grandfather rights". Such franchise rights are generally unlimited as to time. As a result of Exelon's restructuring to separate its regulated and competitive businesses, effective January 1, 2001, both ComEd and PECO transferred their assets and liabilities unrelated to energy delivery to other subsidiaries of Exelon. In the case of ComEd, the assets and liabilities transferred included nuclear generation and wholesale power marketing operations and some administrative functions. In the case of PECO, the assets and liabilities transferred related to nuclear, fossil and hydroelectric generation and wholesale power marketing; unregulated ventures and activities, including communications, infrastructure services and unregulated gas and electric sales activities; and administrative, information technology and other support for other business activities of Exelon and its subsidiaries. Energy Delivery's kilowatthour (kWh) sales and load are generally higher, primarily during the summer periods but also during the winter periods, when temperature extremes create demand for either summer cooling or winter heating. ComEd's highest peak load experienced to date occurred on August 9, 2001 and was 21,574 megawatts (MWs), and the highest peak load experienced to date during a winter season occurred on December 20, 1999 and was 14,484 MWs. PECO's highest peak load experienced to date occurred on July 6, 1999 and was 7,959 MWs; and the highest peak load experienced to date during a winter season occurred on January 17, 2000 and was 6,135 MWs. RETAIL ELECTRIC SERVICES Electric utility restructuring legislation was adopted in Pennsylvania in December 1996 and in Illinois in December 1997. Both states, through their regulatory agencies, established a phased approach to competition, allowing customers to choose an alternative electric generation supplier; required rate reductions and imposed caps on rates during a transition period; and allowed the collection of competitive transition charges (CTCs) from customers to recover costs that might not otherwise be recovered in a competitive market (stranded costs). Under the restructuring initiatives adopted at the Federal and state levels, the role of electric utilities in the supply and delivery of energy is changing. 4 Provider of last resort (POLR) obligations refer to the obligation of a utility to provide generation services (i.e., power and energy) to those customers who do not take service from an alternative generation supplier or who choose to come back to the utility after taking service from an alternative supplier. Because the choice lies with the customer, these obligations make it difficult for the utility to predict and plan for the level of customers and associated energy demand. If these obligations remain unchanged, the utility could be required to maintain reserves sufficient to serve 100% of the service territory load at a tariffed rate on the chance that customers who switched to new suppliers decide to come back to the utility as a "last resort" option. A significant over or under estimation of such reserves may cause commodity price risks for suppliers. ComEd and PECO continue to be obligated to provide a reliable delivery system under cost-based rates. The rates for the generation service provided by ComEd and PECO are subject to rate caps or freezes during all or a portion of the transition periods. ComEd has entered into a long-term power purchase agreement (PPA) with Generation to obtain sufficient power at fixed rates. PECO has entered into a long-term PPA with Generation to obtain sufficient power at the rates PECO is allowed to charge to serve customers who do not choose an alternate generation supplier. ComEd. Under the Illinois legislation, as of December 31, 2000, all non-residential customers were eligible to choose a new electric supplier or elect the power purchase option (PPO), which allows the purchase of electric energy from ComEd at market-based prices. As of December 31, 2001, approximately 18,700 non-residential customers, representing approximately 22% of ComEd's annual retail kWh sales, had elected to receive their electric energy from an alternative retail electric supplier (ARES) or had chosen the PPO. Customers who receive energy from an ARES continue to pay a delivery charge. ComEd's residential customers become eligible to choose a new electric supplier in May 2002. 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, 2005. A 15% residential base rate reduction became effective on August 1, 1998 and a further 5% residential base rate reduction became effective in October 2001. A utility may request a rate increase during the rate freeze period only when necessary to ensure the utility's financial viability. Under the Illinois legislation, if the earned return on common equity of a utility during this period exceeds an established threshold, one-half of the excess earnings must be refunded to customers. The threshold rate of return on common equity is based on the 30-Year Treasury Bond rate plus 8.5% in the years 2000 through 2004. Earnings for purposes of ComEd's threshold include ComEd's net income calculated in accordance with generally accepted accounting principles and reflect the amortization of regulatory assets and goodwill. As a result of the Illinois legislation, at December 31, 2001, ComEd had a regulatory asset with an unamortized balance of $277 million that it expects to fully recover and amortize by the end of 2004. Consistent with the provisions of the Illinois legislation, regulatory assets may be recovered at amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold. The earned return on common equity and the threshold return on common equity for ComEd are each calculated on a two-year average basis. ComEd did not trigger the earnings sharing provision in 2000 or 2001 and does not currently expect to trigger the earnings sharing provisions in the years 2002 through 2004. The Illinois legislation also provided for the collection of a CTC from customers who choose to purchase electric energy from an ARES or elect the PPO during a transition period that 5 extends through 2006. The CTC, which was established as of October 1, 1999 and is applied on a cents per kWh basis, considers the revenue that would have been collected from a customer under tariffed rates, reduced by the revenue the utility will receive for providing delivery services to the customer, the market price for electricity and a defined mitigation factor, which represents the utility's opportunity to develop new revenue sources and achieve cost savings. The CTC allows ComEd to recover some of its costs that might otherwise be unrecoverable under market-based rates. As part of a settlement agreement between ComEd and the City of Chicago relating to ComEd's Chicago franchise agreement, ComEd and Chicago agreed to a revised combination of ongoing work under the franchise agreement and new initiatives that total approximately $1 billion in defined transmission and distribution expenditures by ComEd to improve electric service in Chicago, of which approximately $940 million has been expended through December 31, 2001. The Illinois legislation also committed ComEd to spend at least $2 billion during the period 1999 through 2004 on transmission and distribution facilities outside of Chicago, which has been expended as of December 31, 2001. In addition, ComEd conducted an extensive evaluation of the reliability of its transmission and distribution systems in response to several outages in the summer of 1999. As a result of the evaluation, ComEd has increased its capital and operating and maintenance expenditures on its transmission and distribution facilities in order to improve their reliability. As a result of ComEd's commitments to improve the reliability of its transmission and distribution system, ComEd expects its capital expenditures will exceed depreciation on its rate base assets through at least 2002. The base rate freeze will generally preclude rate recovery of and on such investments prior to January 1, 2005. Unless ComEd can offset the additional carrying costs against cost savings, its return on investment will be reduced during the period of the rate freeze and until rate increases are approved authorizing a return of and on this new investment. In addition, the Illinois legislation provides that an electric utility, such as ComEd, will be liable for actual damages suffered by customers in the event of a continuous power outage of four hours or more affecting 30,000 or more customers and provides for reimbursement of governmental emergency and contingency expenses incurred in connection with any such outage. The legislation bars recovery of consequential damages. The legislation also allows an affected utility to seek relief from these provisions from the ICC where the utility can show that the cause of the outage was unpreventable damage due to weather events or conditions, customer tampering or third party causes. The Illinois legislation also allows a portion of ComEd's future revenues to be segregated and used to support the issuance of securities by ComEd or a special purpose financing subsidiary. The proceeds, net of transaction costs, from such securities issuances must be used to refinance outstanding debt or equity or for certain other limited purposes. The total amount of such securities that may be issued is approximately $6.8 billion. In December 1998, special purpose financing subsidiaries of ComEd issued $3.4 billion of notes. For additional information, see Other Subsidiaries of ComEd and PECO with Publicly Held Securities below and ITEM 8. Financial Statements and Supplementary Data - ComEd, Note 10 of Notes to Consolidated Financial Statements. 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, 2001, approximately 28% of PECO's residential load, 6% of its small commercial and industrial load and 5% of its large commercial and industrial load were purchasing generation service from alternative suppliers. 6 In addition to retail competition for generation services, PECO's settlement of its restructuring case mandated by the Competition Act required PECO to provide generation services to customers who do not or cannot choose an alternate supplier through December 31, 2010 and established caps on generation and distribution rates. The 1998 settlement also authorized PECO to recover $5.3 billion of stranded costs and to securitize up to $4.0 billion of its stranded cost recovery. Under the 1998 settlement, PECO's distribution rates were capped through June 30, 2005 at the level in effect on December 31, 1996. Generation rates, consisting of the charge for stranded cost recovery and a shopping credit or capacity and energy charge, were capped through December 31, 2010. For 2002, the generation rate cap is $0.0698 per kWh, increasing to $0.0751 per kWh in 2006 and $0.0801 per kWh in 2007. The rate caps are subject to limited exceptions, including significant increases in Federal or state taxes or other significant changes in law or regulations that would not allow PECO to earn a fair rate of return. Pursuant to a settlement related to PECO's request for authorization to securitize an additional $1 billion of its stranded cost recovery, PECO provided its customers with additional rate reductions of $60 million in 2001. Under the settlement agreement entered into by PECO in 2000 relating to the PUC's approval of the Merger, PECO agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through 2005 and extended the rate cap on distribution rates through December 31, 2006. PECO has been authorized to recover stranded costs of $5.3 billion over a twelve-year period ending December 31, 2010 with a return on the unamortized balance of 10.75%. PECO's recovery of stranded costs is based on the level of transition charges established in the settlement of PECO's restructuring case and the projected annual retail sales in PECO's service territory. Recovery of transition charges for stranded costs and PECO's allowed return on its recovery of stranded costs are included in operating revenue. As a mechanism for utilities to recover their allowed stranded costs, the Competition Act provides for the imposition and collection of non-bypassable CTCs on customers' bills. CTCs are assessed to and collected from all retail customers who have been assigned stranded cost responsibility and access the utilities' transmission and distribution systems. As the CTCs are based on access to the utility's transmission and distribution system, they will be assessed regardless of whether such customer purchases electricity from the utility or an alternate electric generation supplier. The Competition Act provides, however, that the utility's right to collect CTCs 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. In consideration with the settlement agreement, entered into by PECO with the PUC, PECO developed certain forward-looking financial information during 1998, which was part of this settlement agreement with the PUC. The following table shows the estimated average levels of stranded cost recovery and the amortization of the remaining portion of PECO's authorized stranded cost recovery ($4.9 billion at December 31, 2001) for the years 2002 through 2010, based on estimated 0.8% annual sales growth assumed in the 1998 settlement of PECO's restructuring case. 7 PECO Annual Stranded Cost Amortization And Return

Stranded Cost Revenue Excluding Recovery Gross Receipts Tax Year Annual Sales (1) Charge (2) ---------------------------------------------------- Total Return @ 10.75% Amortization ----- ----------------- --------------- ---------- ----------------- --------------- MWh $/kWh ($000) ($000) ($000) 2002 34,381,485 0.0251 825,004 516,869 308,135 2003 34,656,537 0.0247 818,352 482,401 335,951 2004 34,933,789 0.0243 811,540 444,798 366,742 2005 35,213,260 0.0240 807,933 403,555 404,378 2006 35,494,966 0.0266 902,623 353,070 549,553 2007 35,778,925 0.0266 909,844 290,627 619,217 2008 36,065,157 0.0266 917,123 220,312 696,811 2009 36,353,678 0.0266 924,459 141,229 783,231 2010 36,644,507 0.0266 931,855 52,381 879,474 ----- ----------------- --------------- ---------- ----------------- ---------------

(1) Subject to reconciliation of actual sales and collections. (2) Subject to periodic adjustments for over- or under- recovery. Under the Competition Act, licensed entities, including alternate electric generation suppliers, may act as agents to provide a single bill and provide associated billing and collection services to retail customers located in PECO's retail electric service territory. In that event, the alternative supplier or other third party replaces the customer as the obligor with respect to the customer's bill and PECO generally has no right to collect such receivable from the customer. Third-party billing would change PECO's customer profile (and risk of non-payment by customers) by replacing multiple customers with the entity providing third-party billing for those customers. PUC-licensed entities may also finance, install, own, maintain, calibrate and remotely read advanced meters for service to retail customers in PECO's retail electric service territory. To date, no third parties are providing billing of PECO's charges to customers or advanced metering. Only PECO can physically disconnect or reconnect a customer's distribution service. As permitted by the Competition Act and the 1998 settlement of its restructuring case, PECO securitized $1 billion and $4 billion of its stranded cost recovery in 2000 and 1999, respectively, by the issuance of transition bonds (Transition Bonds) through a special purpose financing entity. As required by the Competition Act, the proceeds from the securitizations were applied to reduce stranded costs, including related capitalization of PECO. In March 2001, approximately $805 million of the first series of Transition Bonds were refinanced. For additional information, see Other Subsidiaries of ComEd and PECO with Publicly Held Securities below and ITEM 8. Financial Statements and Supplementary Data - PECO, Note 11 of Notes to Consolidated Financial Statements. PECO's settlement of its restructuring case included a number of provisions designed to encourage competition for generation services. Shopping credits for generation service may provide an economic incentive for customers to choose an alternate supplier. Effective January 1, 2001, PECO agreed to assign 20% of its non-shopping residential customers to competitive default service provided by one or more alternate suppliers. If on January 1, 2003, 50% of PECO's residential and commercial customers are not obtaining generation services from 8 alternate generation suppliers, than non-shopping customers will be assigned to alternate generation suppliers to reach that level. On November 29, 2000, the PUC approved PECO's bilateral contract with New Power Company (New Power) to move 22% of PECO's non-shopping residential customers to New Power for competitive default generation service. Under this contract, New Power agreed to provide generation services through January 2004, at specified discounted rates, to nearly 300,000 residential customers of PECO who were taking their generation service from PECO. On February 22, 2002 New Power sent PECO a notice of intent to withdraw from the market and return the New Power customers to PECO in May 2002. In addition to the New Power contract, PECO has also entered into a contract with Green Mountain Energy Company (Green Mountain) to assign 50,000 of PECO's non-shopping residential customers to Green Mountain for competitive default generation service, on the same terms and conditions as the New Power contract. On February 21, 2001, the PUC approved the Green Mountain contract. Beginning in May 2001, Green Mountain enrolled approximately 44,000 customers and as of December 31, 2001, approximately 13,000 customers, or 25%, have opted to return to PECO. TRANSMISSION SERVICES Energy Delivery provides wholesale and unbundled retail transmission service under rates established by FERC. FERC has used its regulation of transmission to encourage competition for wholesale generation services and the development of regional structures to facilitate regional wholesale markets. In December 1999, FERC issued Order No. 2000 (Order 2000) requiring jurisdictional utilities to file a proposal to form a regional transmission organization (RTO) or, alternatively, to describe efforts to participate in or work toward participating in an RTO or explain why they were not participating in an RTO. Order 2000 is generally designed to separate the governance and operation of the transmission system from generation companies and other market participants. ComEd. In response to Order 2000, ComEd and several other utilities filed a business plan in August 2001 with FERC describing the creation of Alliance Transmission Company, LLC (Alliance Transco or Alliance) as an independent, for-profit transmission company. In connection with the process leading to the FERC filing, ComEd issued a non-binding declaration of intent to divest to Alliance Transco transmission facilities having a gross book value in excess of $1 billion. In a related action, ComEd entered into a non-binding memorandum of understanding with National Grid USA (National Grid), the proposed manager of Alliance Transco, setting forth general principles relating to the divestiture and Alliance Transco as a basis for further discussion. On December 20, 2001, FERC issued several orders relating to RTOs operating in the Midwest. In those orders, FERC, among other things, approved Midwest Independent Transmission System Operator, Inc. (MISO) as an RTO and found that Alliance Transco lacked sufficient scope to be a stand-alone RTO. FERC also directed the Alliance participants to explore with the MISO how the participants' business plan can be accommodated with the MISO operational framework and dismissed the business plan filed in August 2001 by the Alliance participants. In addition, FERC determined that National Grid is not a market participant within the meaning of Order 2000 and, thus, is eligible to become the managing member of Alliance Transco if that entity is formed. FERC further directed the Alliance participants to file a statement of their plans to join an RTO, including timeframes, within 60 days. As a result of the 9 FERC orders, representatives of ComEd and the other Alliance participants are exploring various RTO participation options and are meeting with representatives of MISO to explore how the Alliance Transco may operate under the MISO. The Alliance participants, including ComEd, filed their discussions with MISO at the FERC in February 2002, noting progress as to some issues, but also noted negotiations were ongoing. The Alliance participants also noted that they were exploring the possibility of filing their business plan within an RTO other than MISO. Following further discussions, the Alliance participants and the National Grid concluded that further negotiations with the MISO required policy resolutions from FERC. Accordingly, on March 6, 2002, the Alliance participants and National Grid submitted a petition to FERC for a declaratory order finding that the proposed policy resolutions contained in the petition provide an appropriate basis for the participation of the Alliance participants in the MISO. The filing requests FERC to approve a proposed division of responsibilities between National Grid and the MISO. It also seeks approval to use existing systems for startup of operations in order to speed up initial operations. It requests approval for the Alliance participants to purchase services from the MISO at incremental costs, and that the MISO refund the $60 million withdrawal fee, plus interest, to ComEd, Illinois Power Company (Illinois Power), and Ameren Corporation (Ameren), of which ComEd's portion is $36 million. The $36 million was paid to the MISO by ComEd in May 2001 under a FERC approved settlement agreement allowing ComEd, Illinois Power, and Ameren to withdraw from the MISO to join the Alliance Transco. PECO. PECO provides regional transmission service pursuant to a regional open-access transmission tariff filed by it and the other transmission owners who are members of PJM Interconnection, LLC (PJM). PJM is a power pool that integrates, through central dispatch, the generation and transmission operations of its member companies across a 50,000 square mile territory. 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. PJM's Office of Interconnection is the Independent System Operator (ISO) for PJM (PJM ISO) and is responsible for operation of the PJM control area and administration of the PJM open-access transmission tariff. PECO and the other transmission owners in PJM have turned over control of their transmission facilities to the PJM ISO. The PJM ISO and the transmission owners who are members of PJM, including PECO, have filed with FERC for approval of PJM as an RTO. FERC has conditionally approved the PJM RTO. GAS Historically, PECO's gas sales and gas transportation revenues were derived pursuant to rates regulated by the PUC. Since 1984, large commercial and industrial customers have been able to choose their gas suppliers. The PUC established, through regulated proceedings, the base rates that PECO may charge for gas service in Pennsylvania. PECO's gas rates are subject to quarterly adjustments designed to recover or refund the difference between the actual cost of purchased gas and the amount included in base rates and to recover or refund increases or decreases in certain state taxes not recovered in base rates. Effective July 1, 2000, the Pennsylvania Natural Gas Choice and Competition Act expanded the choice of gas suppliers to residential and small commercial customers and eliminated the 5% gross receipts tax on gas distribution companies' sales of gas. Approximately one-third of PECO's current total yearly throughput is supplied by third parties. The Act permits gas distribution companies to continue to make regulated sales of gas, at cost, to their customers. The Act does not deregulate the transportation service provided by gas distribution companies, 10 which remains subject to rate regulation. Gas distribution companies continue to provide billing, metering, installation, maintenance and emergency response services. PECO's natural gas supply is provided by purchases from a number of suppliers for terms of up to five years. These purchases are delivered under several long-term firm transportation contracts. PECO's aggregate annual entitlement under these firm transportation contracts is 45 million dekatherms. Peak gas is provided by PECO's liquefied natural gas facility and propane-air plant. PECO also has under contract 21.3 million dekatherms of underground storage through service agreements. Natural gas from underground storage represents approximately 34% of PECO's 2001-2002 heating season supplies. CONSTRUCTION BUDGET The following table shows Exelon's most recent estimate of capital expenditures for plant additions and improvements for ComEd and PECO for 2002 (in millions):

ComEd PECO ------------------------------------------------------------------------------- Transmission and Distribution $712 $200 Gas -- 69 Other 69 10 ---- ---- Total $781 $279 ==== ====

Approximately two thirds of ComEd's 2002 budgeted capital expenditures and one half of PECO's 2002 budgeted capital expenditures are for additions to or upgrades of existing facilities, including reliability improvements. The remainder of the capital expenditures support customer and load growth. GENERATION GENERAL Generation is one of the largest competitive electric generation companies in the United States, as measured by owned and controlled MWs. Generation combines its large, low-cost generation fleet with an experienced wholesale power marketing operation. It directly owns generation assets in the Mid-Atlantic and Midwest regions with a net capacity of 19,715 MW, including 14,250 MW of nuclear capacity, and also controls another 16,245 MW of capacity in the Midwest, Southeast and South Central regions through long-term contracts. In addition to its owned generation facilities, Generation has acquired a 49.9% interest in Sithe with put and call options, beginning in December 2002, to purchase the remaining 50.1% interest. Sithe develops, owns and operates 27 generation facilities in North America. Currently, Sithe has 3,371 MW of capacity in operation and 5,051 MW under construction or in advanced development. Generation also owns a 50% interest in AmerGen, a joint venture with British Energy plc. AmerGen owns three nuclear stations with total generation capacity of 2,398 MW. Generation's wholesale marketing unit, Power Team, is a major wholesale marketer of energy that uses Generation's generation portfolio, transmission rights and expertise to ensure delivery of generation to Generation's wholesale customers under long-term and short-term contracts. Power Team is responsible for supplying the load requirements of ComEd and PECO and markets the remaining energy in the wholesale and spot markets. 11 GENERATING RESOURCES The generating resources of Generation, including its ownership share of AmerGen and Sithe, consist of the following:

Type of Capacity MW ---------------- ------- Owned Generation Assets (1),(2) Nuclear 14,250 Fossil 3,881 Hydro 1,584 ------ 19,715 Long-term Contracts (3) 16,245 AmerGen and Sithe (2) 2,881 ------ Available Resources 38,841 Under Construction or in Advanced Development (2) 2,521 ------ Total Generating Resources 41,362 ======

(1) See "Fuel" for sources of fuels used in electric generation. (2) Based on Generation's ownership. (3) Contracts range from 1 to 29 years. Generation's owned generation assets are primarily the nuclear generation stations in the Midwest region that were acquired from ComEd and the nuclear, fossil and hydroelectric stations in the Mid-Atlantic region that were acquired from PECO. Generation has a 49.9% interest in Sithe and a 50% interest in AmerGen. Sithe, an independent power producer, owns and operates 27 power generation facilities in North America with approximately 3,371 MW of net generation capacity and has approximately 5,051 MW of capacity under construction or in advanced development. AmerGen owns three nuclear plants with a total capacity of 2,398 MW. The owned generating resources of Generation are located primarily in the Midwest (approximately 50% of capacity) and the Mid Atlantic and New England regions (approximately 49% of capacity). AmerGen's generating resources are also in the Midwest and the Mid Atlantic regions. Sithe's generating resources are primarily in the New England region. In December 2001, Generation agreed to purchase two generation plants located in the Dallas Fort-Worth metropolitan area from TXU Corporation (TXU) to expand its presence in the Texas region. The $443 million purchase of the two natural-gas and oil-fired plants, to be financed through available cash and borrowings from Exelon, will add 2,334 MW capacity. The transaction includes a purchase power and tolling agreement for TXU Energy to purchase power during the months of May through September until September 2006. The closing of the acquisition is subject to certain contingencies including the receipt of the necessary regulatory approvals and is anticipated to occur in the second quarter of 2002. NUCLEAR FACILITIES. Generation has direct ownership interests in eight nuclear generating stations, consisting of 16 units with 14,250 MW of capacity (Exelon share). For additional information, see ITEM 2. Properties. All of the nuclear generating stations are operated by Generation, with the exception of Salem Generating Station (Salem), which is operated by PSE&G Nuclear, LLC. In addition, AmerGen operates three nuclear generating stations 12 consisting of three units with 2,398 MW of capacity, of which Generation's interest is 1,199 MW. In 2001, approximately 54% of Generation's electric supply was generated from the nuclear generating facilities. During 2001 and 2000, the nuclear generating facilities operated by Generation and AmerGen, operated at weighted average capacity factors of 94.4% and 93.8%, respectively. See the AmerGen section, which follows within ITEM 1. Business-Generation, for further discussion of the three nuclear facilities owned by AmerGen. Generation is in the process of increasing the capacity of its nuclear fleet through power uprates and plant modifications and refinements. Power uprate projects involve equipment and instrumentation modifications, which require NRC approval. These power uprate projects have the potential of adding up to 885 MW of capacity by the end of 2003. Generation is also pursuing other capacity additions through plant modifications and refinements of several nuclear units that have the potential of adding between 60 MW and 90 MW of capacity. In 2001, Generation completed the purchase of an additional 3.755% interest in the Peach Bottom Station from Atlantic City Electric Company. Total cash paid for the additional interest, including nuclear fuel, was $7 million. As part of this purchase, nuclear decommissioning funds of $29 million were also transferred to Generation. Generation is now a 50% owner of Peach Bottom. LICENSES. Exelon has 40-year operating licenses for each of its nuclear units. Generation applied to the NRC in July 2001 for renewal of the Peach Bottom 2 and 3 licenses and expects to apply for the extension of the operating license for Dresden 2 and 3 and Quad Cities in 2003. The operating license renewal process takes approximately four to five years from the commencement of the project at a site until completion of the NRC's review. The NRC review process takes approximately two years from the docketing of an application. Each requested license extension is expected to be for 20 years beyond the current license expiration. Depreciation provisions are based on the estimated useful lives of the units, which assume the extension of these licenses for all of the nuclear generating stations. The following table summarizes current operating license expiration dates for Generation's nuclear facilities in service.

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

13 REGULATION OF NUCLEAR POWER GENERATION AND SECURITY. Generation is subject to the jurisdiction of the NRC with respect to its nuclear generating stations. The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security, environmental and radiological aspects of those stations. The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of such licenses. Changes in regulations by the NRC that require a substantial increase in capital expenditures for nuclear generating facilities or that result in increased operating costs of nuclear generating units could adversely affect Exelon and its results of operations. The NRC has revamped its inspection, assessment and enforcement programs for commercial nuclear power plants. The new oversight process uses objective, timely and safety-significant criteria in assessing performance, while seeking to effectively and efficiently regulate the industry. It also takes into account improvements in the performance of the nuclear industry over the past twenty years. Nuclear plant performance is measured by a combination of objective performance indicators and by the NRC inspection program. These are closely focused on those plant activities having the greatest impact on safety and overall risk. In addition, the NRC conducts periodic reviews of the effectiveness of each operator's programs to identify and correct problems. The inspection program is designed to verify the accuracy of performance indicator information and to assess performance based on safety cornerstones that include: o initiating events; o mitigating systems; o integrity of barriers to release of radioactivity; o emergency preparedness; o occupational radiation safety; o public radiation safety; and o physical protection. The NRC evaluates licensee performance by analyzing two distinct inputs: inspection findings resulting from the NRC inspection program and performance indicators reported by the licensees on a quarterly basis. NRC reactor oversight results for the fourth quarter of 2001 indicate performance at levels satisfactory enough to receive routine NRC oversight. With respect to nuclear power plant security issues, in response to the events of September 11, 2001, the NRC issued Safeguards and Threat Advisories to all nuclear power plant licensees, including Generation, requesting that they place their facilities on highest alert security status. In response to the NRC Advisories and on its own initiative, Exelon also implemented enhanced security measures, such as increased guard forces, the erection of additional physical barriers, and heightened communication with authorities at all levels of government. In addition to the Advisories, the NRC began an initiative to perform a "top to bottom" review of its safeguards and security programs and requirements in light of the events of September 11. On February 25, 2002, the NRC issued immediately effective orders modifying the operating licenses for all nuclear power plants to require all licensees, including Generation, to implement certain interim security enhancements. In issuing the orders, the NRC found that these compensatory measures should be implemented "as prudent, interim measures, to address the generalized high-level threat environment . . . ." The orders direct all licensees to provide the NRC a schedule for achieving compliance with the requirements of the orders or explain site- 14 specific circumstances to justify relief or variation from those requirements. In addition, if implementation of any requirement would adversely affect safe operation of a facility, a licensee may either propose an alternate plan for achieving the objectives of the order or provide the NRC a schedule for modifying the facility to address the adverse safety condition(s). All enhancements required by the orders are to be implemented by August 31, 2002. The orders are to remain in effect pending an NRC decision that changes in the threat environment justify a relaxation of the requirements or until the NRC determines that other changes are necessary following a re-evaluation of current security programs. The security requirements imposed by the NRC's orders are currently estimated to increase capital expenditures by approximately $1 million per station for such things as enhanced vehicle barriers, modification to plant facilities and increased size of guard force. NUCLEAR WASTE DISPOSAL. There are no facilities for the reprocessing or permanent disposal of spent nuclear fuel (SNF) currently in operation in the United States, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by nuclear generation facilities in on-site storage pools and, in the case of Peach Bottom and Dresden, some SNF has been placed in dry cask storage facilities. SNF storage pools do not have sufficient storage capacity for the life of the plant and Generation is developing dry cask storage facilities, as necessary to support operations. Under the Nuclear Waste Policy Act of 1982 (NWPA), the United States Department of Energy (DOE) is responsible for the disposal of SNF and other high-level radioactive waste. ComEd and PECO each signed contracts with the DOE (each, Standard Contract) to provide for disposal of SNF from their respective nuclear generation stations. Generation assumed the ComEd and PECO Standard Contracts as part of the restructuring, covering Byron, Braidwood, LaSalle, Quad Cities, Zion, Dresden, Limerick and Peach Bottom. In accordance with the NWPA and the Standard Contract, ComEd and PECO pay the DOE one mill ($.001) per kWh of nuclear generation, net of station use, for the cost of nuclear fuel long-term storage and disposal. This fee may be adjusted, in order to ensure full cost recovery by the DOE. The Standard Contract required ComEd and PECO to pay the DOE a one-time fee applicable to nuclear generation through April 6, 1983. PECO has paid this fee while ComEd exercised its option to pay the one-time fee of $277 million, with interest, just prior to the first delivery of SNF to the DOE. As of December 31, 2001, the unfunded liability for the one-time fee with interest was $843 million. This obligation was assumed by Generation in the corporate restructuring. The NWPA and the Standard Contract required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 1998. The DOE, however, failed to meet that deadline and its performance is expected to be delayed significantly. The DOE's current estimate for opening an SNF permanent disposal facility is 2010. This extended delay in SNF acceptance by the DOE has led to Exelon's adoption of dry storage at its Dresden and Peach Bottom Units and its consideration of dry storage at other units. In July 1998, ComEd filed a complaint against the DOE in the U.S. Court of Federal Claims seeking to recover damages caused by the DOE's failure to honor its contractual obligation to begin disposing of SNF in January 1998. ComEd subsequently moved for partial summary judgment on liability for breach of contract claim. In August 2001, the Court granted ComEd's motion for partial summary judgment for liability on ComEd's breach of contract claim. In November 2001, the DOE filed two partial summary judgment motions relating to certain damage issues in the case, as well as two motions to dismiss claims other than ComEd's breach of contract claim. The Court has deferred briefing on those motions pending completion 15 of discovery on certain damage issues. This litigation was assumed by Generation in the corporate restructuring. In July 2000, PECO entered into an agreement with the DOE relating to Peach Bottom to address the DOE's failure to begin removal of SNF in January 1998, as required by the Standard Contract. Under that agreement, the DOE agreed to provide PECO with credits against PECO's future contributions to the nuclear waste fund over the next ten years to compensate for SNF storage costs incurred as a result of the DOE's breach of the Standard Contract. The agreement also provides that, upon PECO's request, the DOE will take title to the SNF and the interim storage facility at Peach Bottom, provided certain conditions are met. Generation has assumed this contract in restructuring. In November 2000, eight utilities with nuclear power plants filed a Joint Petition for Review against the DOE with the U.S. Court of Appeals for the Eleventh Circuit seeking to invalidate the portion of the agreement providing for credits to PECO against nuclear waste fund payments on the ground that such provision is a violation of the NWPA. PECO intervened as a defendant in that case, which is ongoing. On December 5, 2001, the United States Court of Appeals for the Eleventh Circuit heard oral argument on the utilities' Joint Petition for Review. In April 2001, an individual filed suit against the DOE with the United States District Court for the Middle District of Pennsylvania seeking to invalidate the agreement on the grounds that the DOE has violated the National Environmental Policy Act and the Administrative Procedure Act. PECO intervened as a defendant and moved to dismiss the complaint. The Court has not yet ruled on the motion to dismiss. As a by-product of their operations, nuclear generation units produce low-level radioactive waste (LLRW). LLRW is accumulated at each generation station and permanently disposed of at Federally licensed disposal facilities. The Federal Low-Level Radioactive Waste Policy Act of 1980 (Waste Policy Act) provides that states may enter into agreements to provide regional disposal facilities for LLRW and restrict use of those facilities to waste generated within the region. Illinois and Kentucky have entered into an agreement, although neither state currently has an operational site, and none is currently expected to be operational until after 2011. Pennsylvania, which had agreed to be the host site for LLRW disposal facilities for generators located in Pennsylvania, Delaware, Maryland and West Virginia, has suspended the search for a permanent disposal site. Generation has temporary on-site storage capacity at its nuclear generation stations for limited amounts of LLRW and has been shipping such waste to LLRW disposal facilities in South Carolina and Utah. The number of LLRW disposal facilities is decreasing, and Generation anticipates the possibility of continuing difficulties in disposing of LLRW. Generation is also 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 is estimated to be $150 million per year through 2006, of which Generation's share is approximately $22 million per year. INSURANCE. The Price-Anderson Act limits the liability of nuclear reactor owners to $9.5 billion for claims arising from a single incident. The current limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors. Exelon carries the maximum available commercial insurance of $200 million and the remaining $9.3 billion is 16 provided through mandatory participation in a financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed up to $89 million per reactor per incident, payable at a rate of no more than $10 million per reactor per incident per year. This assessment is subject to inflation and state premium taxes. In addition, the U.S. Congress could impose revenue raising measures on the nuclear industry to pay claims. The Price-Anderson Act is scheduled to expire in August 2002. Although replacement legislation has been proposed from time to time, Exelon is unable to predict whether replacement legislation will be enacted. The Price-Anderson Act and the extensive NRC regulation by the NRC do not preclude claims under state law for personal, property or punitive damages related to radiation hazards. Liability of owners of nuclear power plants currently licensed by the NRC to operate would continue to be limited by the Price-Anderson Act provisions regardless of whether Congress renews the Price-Anderson Act. The renewal of Price-Anderson, however, would be important for any new plants to be licensed in the future. Although several bills proposing the renewal of the Price-Anderson Act are currently pending in the United States Congress, Generation is unable to predict at this time whether renewal will occur before August 1, 2002. Generation maintains property insurance for each nuclear power plant in which Generation has an ownership interest. Generation is responsible for its proportionate share of premiums for such insurance based on its ownership interest. Generation's insurance policies provide coverage for decontamination liability expense, premature decommissioning and loss or damage to nuclear facilities. These policies require that insurance proceeds first be applied to assure that, following an accident, the facility is in a safe and stable condition and can be maintained in such condition. Under Generation's insurance policies, proceeds not already expended to place the reactor in a stable condition must be used to decontaminate the facility. If, as a result of an incident, the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a decommissioning fund that Generation is required to maintain by the NRC. (See "Regulation of Nuclear Facility Decommissioning and Security.") These proceeds would be paid to the fund to make up any difference between the amount of money in the fund at the time of the early decommissioning and the amount that would have been in the fund if contributions had been made over the normal life of the facility. Generation is unable to predict what effect these requirements may have on the timing of the availability of insurance proceeds to creditors and the amount of these proceeds. Under the terms of the various insurance agreements, Generation could be assessed up to $121 million for losses incurred at any plant insured by the insurance companies. Nuclear Electric Institute Limited (NEIL), a mutual insurance company to which Generation belongs, provides property and business interruption insurance for Generation's nuclear operations. One feature of Generation's property insurance through NEIL provides coverage for damages caused by acts of terrorism at any of its nuclear generating stations. This terrorism endorsement to the NEIL policy specifies that its coverage applies to acts of terrorism similar to the September 11, 2001 events. In the event that one or more acts of terrorism cause accidental property damage within a 12-month period from the first accidental property damage under one or more policies for all insureds, the maximum recovery for all losses by all insureds will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity or any other source applicable to such losses. If total property losses exceed available funds under the policy, proportionate recovery is provided to cover a portion of an insured's property losses. The percentage recovery would be equal to the ratio of the insured's property losses and the total of all property losses. Generation's insurance through NEIL also provides replacement power cost insurance in the event of a major accidental outage at a nuclear station. The policy provides for a waiting 17 period before recovery of costs can commence. The premium for this coverage is subject to assessment for adverse loss experience, with a maximum assessment of $46 million per year. Recovery under this insurance for terrorist acts is subject to the $3.2 billion aggregate limit and secondary to the property insurance described above. In addition, Generation participates in the American Nuclear Insurers Master Worker Program, which provides coverage for worker tort claims filed for bodily injury caused by a nuclear energy accident. This program was modified, effective January 1, 1998, to provide coverage to all workers whose nuclear-related employment began on or after the commencement date of reactor operations. Generation will not be liable for a retroactive assessment under this new policy. However, in the event losses incurred under the small number of policies in the old program exceed accumulated reserves, a maximum retroactive assessment of up to $50 million could apply. Generation does not carry any business interruption insurance other than the NEIL coverage for nuclear operations. Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained. Such losses could have a material adverse effect on Generation's financial condition and results of operations. DECOMMISSIONING. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. Based on estimates of decommissioning costs for each of the nuclear facilities in which Generation has an ownership interest, the ICC permits ComEd and the PUC permits PECO to collect from its customers and deposit in segregated accounts amounts which, together with earnings thereon, will be used to decommission such nuclear facilities. As of December 31, 2001, Generation's estimate of its nuclear facilities' decommissioning cost is $7.2 billion in current year dollars. The liability for decommissioning each generation station is recognized ratably over that generating station's service life. At December 31, 2001, the decommissioning liability recorded in accumulated depreciation and deferred credits and other liabilities was $2.7 billion and $1.3 billion, respectively. Decommissioning expenditures are expected to occur primarily after the plants are retired and are currently estimated to begin in 2029 for plants currently in operation. Decommissioning costs are currently recoverable by ComEd and PECO through regulated rates and are remitted to Generation for deposit in the decommissioning trust funds. In 2001, ComEd and PECO collected from customers and remitted to Generation approximately $102 million in decommissioning costs. Generation believes that the amounts being remitted to it by ComEd and PECO and the earnings on nuclear decommissioning trust funds will be sufficient to fully fund Generation's decommissioning obligations. In connection with the transfer of ComEd's nuclear generating stations to Generation, ComEd asked the ICC to approve the continued recovery of decommissioning costs after the transfer. On December 20, 2000, the ICC issued an order finding that the ICC has the legal authority to permit ComEd to continue to recover decommissioning costs from customers for the six-year term of the PPAs between ComEd and Generation. Under the ICC order, ComEd is permitted to recover $73 million per year from customers for decommissioning for the years 2001 through 2004. In 2005 and 2006, ComEd can recover up to $73 million annually, depending upon the portion of the output of the former ComEd nuclear stations that ComEd purchases from Generation. Under the ICC order, subsequent to 2006, there will be no further recoveries of decommissioning costs from customers. The ICC order also provides that any surplus funds after the nuclear stations are decommissioned must be refunded to customers. The ICC order is currently pending on appeal in the Illinois Appellate Court. 18 Zion, a two-unit nuclear generation station, and Dresden Unit 1 formerly owned by ComEd, have permanently ceased power generation. ComEd transferred Zion and Dresden Unit 1 as well as their related decommissioning liabilities and trust funds to Generation as part of Exelon's corporate restructuring. Zion's and Dresden Unit 1's spent nuclear fuel is currently being stored in on-site storage pools until a permanent repository under the NWPA is completed. Generation has recorded a liability of $1.3 billion, which represents the estimated cost of decommissioning Zion and Dresden Unit 1 in current year dollars. Decommissioning expenditures are expected to occur primarily after 2013 and 2030 for Zion and Dresden Unit 1, respectively. FOSSIL AND HYDROELECTRIC FACILITIES. Fossil units include: o base-load units -- the coal-fired units at Eddystone and Cromby and our interests in the Keystone and Conemaugh Stations; o intermediate units -- the Eddystone and Cromby units that have dual fuel (oil/gas) capability; and o peaking units -- oil- or gas-fired steam turbines, combustion turbines and internal combustion units at various locations. Hydroelectric facilities include: o base-load units-- at the Conowingo run-of-river hydroelectric facility on the Susquehanna River in Harford County, Maryland; and o intermediate units-- at the Muddy Run pumped-storage hydroelectric facility in Lancaster County, Pennsylvania. Generation operates all of its fossil and hydroelectric facilities other than La Porte, Keystone and Conemaugh. In 2001, approximately 3% of electric output was generated from our owned fossil and hydroelectric generation facilities. The majority of this output was dispatched to support Generation's power marketing activities. Generation is in the process of extensively renovating the Conowingo and Muddy Run control systems to improve plant efficiency. Generation is planning to overhaul 4 units at Conowingo, which is expected to increase capacity by 10 MW per unit. The controls at all combustion turbine facilities have been re-configured to provide remote start capability for all units, enabling immediate response time to capture fluctuations in electric market prices. LICENSES. Fossil generation plants are generally not licensed and, therefore, the decision on when to retire plants is fundamentally an economic one. Hydroelectric plants are licensed by FERC. The Muddy Run and Conowingo facilities have licenses that expire in September 2014. Generation is considering applying to FERC for license extensions of 40 years for both plants, but the duration of any license extension will depend on then-current policies at FERC. The process of applying for an extension to an existing hydroelectric license generally takes at least eight years. 19 LONG-TERM CONTRACTS. In addition to owned generation assets, Generation sells electricity purchased under the long-term contracts described below:

Seller Location Expiration Capacity (MW) ----------------------------- --------------------- ------------- -------------- Midwest Generation, LLC Various in Illinois 2004 9,105 Kincaid Generation, LLC Kincaid, Illinois 2012 1,158 Tenaska Georgia Partners, LP Franklin, Georgia 2029 900 Tenaska Frontier, Ltd Shiro, Texas 2020 830 Others Various 2002 to 2022 4,252 -------------- Total 16,245 ==============

MIDWEST GENERATION, LLC CONTRACT. Generation is a party to contracts with Midwest Generation, LLC (Midwest Generation), a subsidiary of Edison Mission Energy. Under the contracts, Generation initially had the right to purchase through 2004 the capacity and energy associated with approximately 9,460 MW of fossil-fired generation stations located in Northern Illinois, formerly owned by ComEd. The generation units include base-load, intermediate and peaking units. Under the contracts, Generation pays a fixed capacity charge that varies by season and a fixed energy charge. The capacity charge is reduced to the extent the plants are unable to generate and deliver energy when requested. Under the contracts, Generation has annual rights to reduce the capacity and related energy purchase obligations, and some of these rights were recently exercised. Effective January 1, 2002, Generation has released all of the 355 MW of oil-fixed peaking capacity that is covered by the contracts, and will decide whether to exercise yearly options in 2003 and 2004 depending on the projected need for capacity and energy to fulfill obligations under the agreement with ComEd or otherwise, taking into account forward market conditions and other alternatives. Finally, Generation is in arbitration with Midwest Generation under the contract relating to the unavailability of certain units in January 2001. FEDERAL POWER ACT The Federal Power Act gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to FERC's jurisdiction are required to file rate schedules with FERC with respect to wholesale sales or transmission of electricity. Tariffs established under FERC regulation give Generation access to transmission lines that enables it to participate in competitive wholesale markets. Because Generation sells power in the wholesale markets, Generation is deemed to be a public utility for purposes of the Federal Power Act and is required to obtain FERC's acceptance of the rate schedules for wholesale sales of electricity. Generation has received authorization from FERC to sell energy at market-based rates. As is customary with market-based rate schedules, FERC reserved the right to suspend market-based rate authority on a retroactive basis if it is subsequently determined that Generation or any of its affiliates exercised or have the ability to exercise market power. FERC is also authorized to order refunds if it finds that market-based rates are unreasonable. In April 1996, FERC issued Order 888 (Order 888). The intent of Order 888 was to open the transmission grid subject to FERC's jurisdiction to all eligible customers, including sellers of power and retail customers, in states where retail access is approved. Order 888 requires that owners of transmission facilities provide access to their transmission facilities under filed tariffs at cost-based rates. In connection with Order 888, FERC issued Order 889 (Order 889). Under Order 889, PECO and ComEd were required to file Standards of Conduct, which governed the 20 communication of non-public information between transmission personnel and employees of any affiliated wholesale merchant function. FERC recently issued a Notice of Proposed Rulemaking for the Standards of Conduct for Transmission Providers. Among other things, FERC is considering whether it would be appropriate for it to adopt measures that would limit the amount of capacity an affiliate can hold in a transmission provider. Generation's business would be impacted if any of these measures were instituted. In December 1999, FERC issued Order 2000, which encourages the voluntary restructuring of transmission operations through the use of independent system operators (ISOs) and RTOs. A result of establishing these entities is to eliminate or reduce transmission charges imposed by successive transmission systems when wholesale generators cross several transmission systems to deliver capacity. During 2000, FERC announced its intention to foster RTO development. Each transmission-owning public utility was required to file a plan to form an RTO, with December 2001 as the target date for operation. In July 2001, FERC conditionally granted RTO status to PJM and, in separate orders, directed that the various proposed RTOs combine into four regional RTOs. However, inconsistencies in the pace of RTO development and significant state public utility commission concerns caused FERC to indefinitely extend its operational target date of December 2001. The latter half of 2001 and early 2002 have brought further change to the electric industry. In early November 2001, FERC announced its intent to complete RTO development using two parallel tracks: (1) address geographic scope and governance of RTOs; and (2) address transmission pricing and market design. Contemporaneously, FERC initiated several immediate steps to move the RTO development process forward. One of these actions was initiation of an effort to standardize generator interconnection (a related effort concerning cost allocation is to be addressed in 2002). Also, FERC issued a Notice of Proposed Ruling on Revised Public Utility Filing Requirements, pursuant to which it is considering mandatory electronic filing of transactional data and additional public filing requirements. Several other actions by FERC are important. First, FERC announced in late November 2001 a new market power test, the Supply Margin Assessment (SMA) screen. Under the SMA, if within a particular geographic market an energy company's generation capacity exceeds the market's surplus capacity above peak demand then the test is failed. Where this occurs, FERC will impose on the company and its affiliates a requirement to offer uncommitted capacity under a cost-based rate structure. The only exemption will be for companies operating under the authority of an ISO or RTO with a FERC-approved market monitoring and mitigation plan. Under this approach, it would be unlikely that a vertically integrated energy company serving franchised retail load would be able to pass the test and maintain market-based rates, unless and until the company was a member of an approved ISO or RTO. Second, FERC continues to exhibit a commitment to increased market monitoring with an intent to ensure that high price volatility, such as was seen in California, does not occur again. As part of this commitment, FERC announced early in 2002 the formation of the Office of Market Oversight and Investigation, which will report directly to the FERC Chairman. This new office will assess, among other things, market performance. It is unclear how Generation's business may be impacted by these initiatives. Finally, in December 2001, FERC approved the Midwest ISO (MISO) as an RTO, which principally resides within the MAPP reliability region. The FERC's action also rejected the stand alone, for-profit RTO structure proposed by the Alliance Companies. FERC, however, indicated that a for-profit transmission company could be formed and successfully integrated into the 21 MISO. Currently, while a significant portion of Exelon's generation is located within the PJM RTO area, other significant generation is located within the MAIN reliability region, where an approved ISO or RTO does not exist. It is possible that under its evolving market power tests, FERC might determine that Generation has market power in this area. If FERC were to suspend Generation's market-based rate authority, it would most likely be necessary to file, and obtain FERC acceptance of, cost-based rate schedules or schedules tied to a public index. In addition, the loss of market-based rate authority would subject Generation to the accounting, record-keeping and reporting requirements that are imposed on public utilities with cost-based rate schedules. FUEL The following table shows sources of electric supply for 2001 and estimated for 2002:

Source of Electric Supply ---------------------------- 2001 2002 (Est.) ------- ------------- Nuclear units 54% 52% Purchases 37% 39% Fossil and hydro units 3% 3% Units operated by others (a) 6% 6% ------- ------------- 100% 100% ------- -------------

(a) Reflects Generation's share of the output of Salem, Keystone and Conemaugh stations, and 100% of the output for LaPorte station, all which are operated by other companies. See ITEM 2. Properties - for further information on Generation's station ownership. The fuel costs for nuclear generation are substantially less than fossil-fuel generation. Consequently, nuclear generation is the most cost-effective way for Generation to meet its commitment to supply the requirements of ComEd, PECO and Enterprise's competitive retail energy sales business, Exelon Energy Inc. (Exelon Energy), and for sales to other utilities. The cycle of production and utilization of nuclear fuel includes the mining and milling of uranium ore into uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, the enrichment of the uranium hexafluoride and the fabrication of fuel assemblies. Generation has uranium concentrate inventory and supply contracts sufficient to meet all of its uranium concentrate requirements through 2003. Generation's contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2004. All of Generation's enrichment requirements have been contracted through 2004. Contracts for fuel fabrication have been obtained through 2005. Generation does not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment or fabrication services for its nuclear units. Generation obtains approximately 25% of its uranium enrichment services from European suppliers. There is an ongoing trade action by USEC, Inc. (USEC) alleging dumping in the United States against European enrichment services suppliers. In January 2002, the U.S. International Trade Commission determined that USEC was "materially injured or threatened with material injury" by low-enriched uranium exported by European suppliers. The U.S. Department of Commerce (DOC) has assessed countervailing and anti-dumping duties against the European suppliers. Both USEC and the European suppliers have appealed these decisions. Exelon is uncertain at this time as to the outcome of the pending appeals, however as a result of these actions Exelon may incur higher costs for uranium enrichment services necessary for the production of nuclear fuel. 22 FUEL MANAGEMENT. Coal is obtained for coal-fired plants primarily through annual contracts with the remainder supplied through either short-term contracts or spot-market purchases. Natural gas is procured through annual, monthly and spot-market purchases. Some fossil generation stations can use either oil or gas as fuel. Fuel oil inventories are managed such that in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months inventory levels are managed to take advantage of favorable market pricing. In 2001, the use of financial instruments to mitigate price risk associated with multi-commodity price exposures was started. Generation also hedges forward price risk with both over-the-counter and exchange-traded instruments. POWER TEAM Power Team competes nationally in wholesale power marketing on the basis of price and service offerings, using Generation's generation assets, transmission access, reservations and its knowledge of the interconnected bulk power systems and developing markets to assure customers of energy delivery. Through Power Team, Generation enters into bilateral arrangements for the purchase, sale and delivery of capacity, energy and ancillary services. Sales agreements are with load-serving entities, including electric utilities, municipalities, electric cooperatives, retail load aggregators and other wholesale market participants. Through Power Team, Generation also competes in the wholesale spot markets for electricity. Generation has agreements with ComEd and PECO to supply their respective load requirements for customers through 2006 and 2010, respectively. See Item 8. Financial Statements and Supplementary Data - ComEd, Note 2, and PECO Note 2. Generation has also contracted with Exelon Energy to meet its supply commitments pursuant to its competitive retail generation sales agreements. Under the agreements with ComEd and PECO, Generation will supply all of ComEd and PECO's needs to supply customers who do not select an alternative electric generation supplier through the end of the respective transition periods. Therefore, the supply requirements under the agreements will vary depending on how much of the load has selected an alternative supplier. Power Team also manages the price and supply risks for energy and fuel associated with generation assets and the risks of power marketing activities. Through Power Team, Generation began to use financial and commodity contracts for trading purposes in the second quarter of 2001. The trading activities represent a very limited portion of Generation's overall power marketing activities. For example, the limit on new purchases of electricity for any forward month represents less than 5% of the owned and contracted supply of electricity. The trading portfolio is planned to grow modestly in 2002, subject to stringent risk management limits and policies including volume, stop-loss and value-at-risk limits to manage exposure to market risk. Additionally, Generation has a financial risk management policy and a corporate risk group to monitor the financial risks of its power marketing activities. Financial trading, together with the effects of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 133 "Accounting for Derivatives and Hedging Activities" (SFAS No. 133), may cause volatility in Generation's future results of operations. 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 23 operational failure of one of its owned or contracted power generating units. Generation has also contracted for access to additional generation through bilateral long-term PPAs. These agreements are commitments related to power generation of specific generation plants and/or are dispatchable in nature similar to asset ownership. Generation enters into PPAs with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to customers. Excess power is sold in the wholesale market. Generation has also purchased transmission service to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs. The intent and business objective for the use of its capital assets and contracts is to provide Generation with physical power supply to enable it to deliver energy to meet customer needs. Generation has entered into bilateral long-term contractual obligations for sales of energy to load-serving entities including electric utilities, municipalities, electric cooperatives, and retail load aggregators. Generation also enters into contractual obligations to deliver energy to wholesale market participants who primarily focus on the resale of energy products for delivery. Generation provides delivery of its energy to these customers through access to transmission assets or rights for transmission service. In addition, Generation has entered into long-term PPAs with independent power producers under which Generation makes fixed capacity payments in return for exclusive rights to the energy and capacity of the generating units for a fixed period. The terms of the long-term PPAs enable Generation to dispatch energy from the plants. At December 31, 2001, Generation had long-term commitments, relating to the purchase and sale of energy, capacity and transmission rights from unaffiliated utilities and others, including the Midwest Generation and AmerGen contracts, as expressed in the following tables:

Capacity Power Only Power Only Transmission (in millions) Purchases Purchases Sales Rights Purchases --------- ---------- ---------- ----------------- 2002 $1,005 $ 551 $1,803 $ 139 2003 1,214 345 666 31 2004 1,222 346 219 15 2005 406 264 139 15 2006 406 250 58 5 Thereafter 3,657 2,321 22 -- ------ ------ ------ ------ Total $7,910 $4,077 $2,907 $ 205 ====== ====== ====== ======

In addition, in connection with the acquisition of the TXU generating stations, expected to close in the second quarter of 2002, Exelon has agreed to supply TXU with 100% of the station output during the months of May through September from 2002 through 2006. During the periods covered by the power purchase agreement, TXU will make fixed capacity payments and will provide fuel to Exelon in return for exclusive rights to the energy and capacity of the generation plants. 24 CAPITAL EXPENDITURES Generation's estimated capital expenditures for 2002 are as follows:

(in millions) ------------------------------------------------------------------------------------------------------------ Production Plant $ 403 Nuclear Fuel 432 Investments 254 --------- Total $ 1,089 =========

Approximately 75% of Generation's estimated capital expenditures for 2002 are for additions to or upgrades of existing facilities (including nuclear outages), nuclear fuel and increases in capacity at existing plants. The remainder is for asset acquisitions other than the TXU generating station acquisition. SITHE Generation owns 49.9% of the outstanding common stock of Sithe and has an option, beginning on December 18, 2002, to purchase the remaining common stock outstanding (Remaining Interest) in Sithe. The purchase option expires on December 18, 2005. In addition, the Sithe stockholders who own in the aggregate the Remaining Interest have the right to require Generation to purchase the Remaining Interest (Put Rights) during the same period in which Generation can exercise its purchase option. At the end of this exercise period, if Generation has not exercised its purchase option and the other Sithe stockholders have not exercised their Put Rights, Generation will have an additional one-time option to purchase shares from the other stockholders in Sithe to bring Generation's ownership in Sithe from the current 49.9% to 50.1% of Sithe's total outstanding common stock. Sithe presently owns and operates 27 power generation facilities in North America, with approximately 3,371 MW of net merchant generating capacity. It has 4 facilities under construction with an estimated capacity of 2,651 MW and approximately 2,400 MW of generation capacity in various stages of advanced development. On December 31, 2001, Sithe had long-term debt of $2.3 billion, including $2.1 billion of non-recourse project debt, not including any non-recourse project debt associated with Sithe's equity investments. In December 2001, Sithe entered into a new 18-month corporate credit facility for $500 million expiring in June 2003. As of December 31, 2001 Sithe had drawn approximately $176 million under this facility and extended approximately $161 million in letters of credit. Through internally generated cashflows and the corporate credit facility, Sithe has sufficient liquidity to cover all 2002 operating and capital commitments. AMERGEN AmerGen Energy Company, LLC was formed in 1997 by PECO and British Energy plc, (British Energy), to acquire and operate nuclear generation facilities in North America. Currently, AmerGen owns three single-unit nuclear generation facilities, which are described in the table below. AmerGen's nuclear facilities are subject to the provisions and maximum assessment and recovery limits of the Price -Anderson Act and NEIL similar to Generation's, as discussed above within ITEM 1. Business - Generation, however the American Nuclear Insurers Master Worker Program is not applicable to AmerGen as AmerGen purchased its nuclear reactors after 1998. 25 The capacity factors for the AmerGen plants for 2000 and 2001 were 87% and 88.5%, respectively. AmerGen operates these nuclear facilities; however, Generation provides AmerGen with many services, including management services, in connection with the operation and support of these facilities under a Services Agreement dated March 1, 1999. In addition, Generation's chief nuclear officer holds the same position at AmerGen. As part of the restructuring PECO transferred its 50% interest in AmerGen to Generation in January 2001.

License Net Expiration Generation Station Year Acquired Location Date (1) Capacity (MW) ---------------------- ------------- -------------------- ----------- ------------- Clinton Nuclear Power Station 1999 Clinton, IL 2026 933 Unit 1 of Three Mile Island Nuclear Station 1999 Londonderry Twp., PA 2014 835 Oyster Creek Nuclear Generation Facility 2000 Forked River, NJ 2009 630 ----- Total 2,398 =====

(1) AmerGen is reviewing the potential for license renewals for the Oyster Creek Nuclear Generating Facility (Oyster Creek) and Unit 1 of Three Mile Island (TMI-1). As part of each acquisition of its nuclear facilities, AmerGen entered into a power sales agreement with the seller. The agreement with Illinois Power for Clinton Nuclear Power Station (Clinton) is for 75% of the output for a term expiring at the end of 2004. The agreement with GPU, Inc. for TMI-1 and Oyster Creek are for all of the output. Generation purchases the residual energy from Clinton through December 31, 2002. The agreement for the output of Oyster Creek expires on March 31, 2003. The original agreement for the output of TMI-1 expired in 2001. Exelon has agreed to purchase from AmerGen all the energy from TMI after December 31, 2001 through December 31, 2014. AmerGen maintains a decommissioning trust fund for each of its plants in accordance with NRC regulations and believes that amounts in these trust funds, together with investment earnings thereon, and additional contributions for Clinton from Illinois Power will be sufficient to meet its decommissioning obligations. Under its LLC Agreement, AmerGen is managed by or at the direction of a management committee, which consists of six voting representatives, three of whom are appointed by British Energy and three by Generation. In addition, Generation appoints the chairman of the management committee. Action by the management committee generally requires the affirmative vote of a majority of members. Generation may transfer its interest in AmerGen, as may British Energy, subject to a right of first refusal of the other party and to the right of the other party to require a third party buying the interest to also purchase the other party's interest. In February 2002, Generation entered into an agreement to loan AmerGen up to $75 million at an interest rate of 1-month London Interbank Offering Rate plus 2.25%. As of March 31, 2002, $46 million has been loaned to AmerGen. The loan is due November 1, 2002. Exelon has committed to provide AmerGen with capital contributions equivalent to 50% of the purchase price of any acquisitions AmerGen makes in 2002. ENTERPRISES Enterprises consists primarily of the infrastructure services business of InfraSource, Inc. (InfraSource), the energy services business of Exelon Services, Inc., the competitive retail energy sales business of Exelon Energy, the district cooling business of Exelon Thermal Technologies, 26 Inc., communications joint ventures and other investments weighted towards the communications, energy services and retail services industries. The results of InfraSource's infrastructure services business and Exelon Services' energy services business are dependent on demand for outsourced construction and maintenance services. That demand has been driven in the past by the restructuring of the electric utility industry and growth of the communications, cable and internet industries. Slowdown in that restructuring and the current condition of the communications, cable and internet industries means that results will be driven by efforts to manage costs and achieve synergies. InfraSource, formerly Exelon Infrastructure Services, Inc., provides infrastructure services, including infrastructure construction, operation management and maintenance services to owners of electric, gas, cable and communications systems, including industrial and commercial customers, utilities and municipalities, throughout the United States. Since it was established in 1997, InfraSource has acquired thirteen infrastructure service companies. In 2001, InfraSource had revenues of approximately $900 million and employed approximately 8,200 at the end of 2001. Exelon Services is engaged in the design, installation and servicing of heating, ventilation and air conditioning facilities for commercial and industrial customers. Exelon Services also provides energy-related services, including performance contracting and energy management systems. Exelon Energy provides retail electric and gas services as an unregulated retail energy supplier in Illinois, Massachusetts, Michigan, New Jersey, Ohio, Pennsylvania and other areas in the Midwest and Northeast United States. Its retail energy sales business is dependent upon continued deregulation of retail electric and gas markets and its ability to obtain supplies of electricity and gas at competitive prices in the wholesale market. The low margin nature of the business makes it important to achieve concentrations of customers with higher volumes so as to manage costs. Exelon Thermal Technologies provides district cooling and related services to offices and other buildings in the central business district of Chicago and in other cities in North America. District cooling involves the production of chilled water at one or more central locations and its circulation to customers' buildings, primarily for air conditioning. Exelon Communications is the unit of Enterprises through which Exelon manages its communications investments. Exelon Communications' principal investment is PECOAdelphia Communications. PECOAdelphia is a competitive local exchange carrier, providing local and long-distance, point-to-point voice and data communications, internet access and enhanced data services for businesses and institutions in eastern Pennsylvania. PECOAdelphia utilizes a large-scale, fiber-optic cable-based network that currently extends over 700 miles and is connected to major long-distance carriers and local businesses. PECOAdelphia is a 50% owned joint venture with Adelphia Business Solutions. On March 1, 2002, Exelon Communications announced an agreement to sell its 49% interest in AT&T Wireless PCS of Philadelphia, LLC for $285 million in cash. Proceeds from the transaction will be used for Exelon's general corporate purposes. Exelon Capital Partners was created in 1999 as a vehicle for direct venture capital investing in the areas of unregulated energy sales, energy services, utility infrastructure services, 27 e-commerce and communications. At December 31, 2001, Exelon Capital Partners had made direct investments in eight companies, with funding commitments totaling approximately $100 million. The investment mix was weighted toward the communications industry, but also included companies in energy services and retail services, including e-commerce. EMPLOYEES As of December 31, 2001, Exelon and its subsidiaries had approximately 29,200 employees, in the following companies:

ComEd 7,700 PECO 2,700 Generation 7,200 Enterprises 10,600 BSC 1,000 ------ Total 29,200 ======

Approximately 7,000 employees, including 4,900 employees of ComEd, 2,000 employees of Generation and 70 employees of BSC are covered by a collective bargaining agreement with Local 15 of the International Brotherhood of Electrical Workers (IBEW). Exelon and the IBEW Local 15 reached agreement on a new Collective Bargaining Agreement (CBA) in April 2001. The new agreement had an expiration date of March 31, 2004. An agreement to extend the date of the contracts was ratified by the union on December 31, 2001. The new agreements run through September 30, 2005, for Generation, and September 30, 2006 for ComEd and BSC. The new agreements extend the existing CBA, create separate agreements for the major business units and provide for a voluntary severance plan. In addition, approximately 4,900 Enterprises employees are represented by unions, including approximately 2,600 employees who are represented by various local unions of the International Brotherhood of Electrical Workers. The remaining union employees are members of a number of different local unions, including laborers, welders, operators, plumbers and machinists. Over the past several years, a number of unions have filed petitions with the National Labor Relations Board to hold certification elections with regard to different segments of employees within PECO. In all cases, PECO employees have rejected union representation. Exelon expects that such petitions, related to segments of employees at PECO, Generation and Enterprises, will continue to be filed in the future. ENVIRONMENTAL REGULATION GENERAL Specific operations of Exelon, primarily those of Generation, are subject to regulation regarding environmental matters by the United States and by various states and local jurisdictions where Exelon operates its facilities. The Illinois Pollution Control Board (IPCB) has jurisdiction over environmental control in the State of Illinois, together with the Illinois Environmental Protection Agency, which enforces regulations of the IPCB and issues permits in connection with environmental control. The Pennsylvania Department of Environmental Protection (PDEP) has jurisdiction over environmental control in the Commonwealth of Pennsylvania. State regulation 28 includes the authority to regulate air, water and noise emissions and solid waste disposals. The United States Environmental Protection Agency (EPA) administers certain Federal statutes relating to such matters as do various interstate and local agencies. WATER Under the Federal Clean Water Act, National Pollutant Discharge Elimination System (NPDES) permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated. Those permits must be renewed periodically. Generation either has NPDES permits for all of its generating stations or has pending applications for such permits. Generation is also subject to the jurisdiction of certain other state and interstate agencies, including the Delaware River Basin Commission and the Susquehanna River Basin Commission. SOLID AND HAZARDOUS WASTE The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. Government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of waste at sites, most of which are listed by the EPA on the National Priorities List (NPL). These potentially responsible parties (PRPs) can be ordered to perform a cleanup, can be sued for costs associated with a EPA-directed cleanup, may voluntarily settle with the U.S. Government concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation under state oversight prior to listing on the NPL. Various states, including Illinois and Pennsylvania, have enacted statutes that contain provisions substantially similar to CERCLA. In addition, the Resource Conservation and Recovery Act (RCRA) governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted. ComEd, PECO and Generation and their subsidiaries are or are likely to become parties to proceedings initiated by the EPA, state agencies and/or other responsible parties under CERCLA and RCRA with respect to a number of sites, including manufactured gas plant (MGP) sites, or may undertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third party. By notice issued in November 1986, the EPA notified over 800 entities, including ComEd and PECO, that they may be PRPs under CERCLA with respect to releases of radioactive and/or toxic substances from the Maxey Flats disposal site, a LLRW disposal site near Moorehead, Kentucky, where ComEd and PECO wastes were deposited. A settlement was reached among the Federal and private PRPs, including ComEd and PECO, the Commonwealth of Kentucky and the EPA concerning their respective roles and responsibilities in conducting remedial activities at the site. Under the settlement, the private PRPs agreed to perform the initial remedial work at the site and the Commonwealth of Kentucky agreed to assume responsibility for long-range maintenance and final remediation of the site. On April 18, 1996, a consent decree, which included the terms of the settlement, was entered by the United States District Court for the Eastern District of Kentucky. The PRPs have entered into a contract for the design and 29 implementation of the remedial plan and work has commenced. As a result of restructuring, ComEd's and PECO's liability and obligations arising from the Maxey Flats site have been transferred to Generation. Exelon estimates that its share of remediation costs will not be material. By notice issued in December 1987, the EPA notified several entities, including PECO, that they may be PRPs under CERCLA with respect to wastes resulting from the treatment and disposal of transformers and miscellaneous electrical equipment at a site located in Philadelphia, Pennsylvania (the Metal Bank of America site). Several of the PRPs, including PECO, formed a steering committee to investigate the nature and extent of possible involvement in this matter. On May 29, 1991, a Consent Order was issued by the EPA pursuant to which the members of the steering committee agreed to perform the remedial investigation and feasibility study as described in the work plan issued with the Consent Order. PECO's share of the cost of study was approximately 30%. On July 19, 1995, the EPA issued a proposed plan for remediation of the site, which involves removal of contaminated soil, sediment and groundwater and which the EPA estimated would cost approximately $17 million to implement. On June 26, 1998, the EPA issued an Order to the non-de minimis PRP group members, and others, including the owner, to implement the remedial design (RD) and remedial action (RA). The PRP Group is proceeding as required by the Order. It has selected a contractor which has been approved by the EPA, and, on November 5, 1998, submitted the draft RD work plan. The EPA has approved the PRP Group's RD work plan and based upon the RD investigation, the EPA has modified the work plan. On March 5, 2001, the PRP group submitted a revised RD to the EPA, in which it estimates the cost to implement the RA to range from $14 million to $27 million. The EPA and the PRPs are also involved in litigation with the site owner concerning remediation liability. PECO is unable to estimate its share of the costs of the remedial activities. MGP SITES MGPs manufactured gas in Illinois and Pennsylvania from approximately 1850 to 1950. ComEd generally did not operate MGPs as a corporate entity but did, however, acquire MGP sites as part of the absorption of smaller utilities. Approximately half of these sites were transferred to Nicor Gas as part of a general conveyance in 1954. ComEd also acquired former MGP sites as vacant real estate on which ComEd facilities have been constructed. To date, ComEd has identified 44 former MGP sites for which it may be liable for remediation. Similarly, PECO has identified 28 sites where former MGP activities may have resulted in site contamination. With respect to these sites, ComEd and PECO are presently engaged in performing various levels of activities, including initial evaluation to determine the existence and nature of the contamination, detailed evaluation to determine the extent of the contamination and the necessity and possible methods of remediation, and implementation of remediation. Overseeing state regulatory agencies have approved the remediation of five MGP sites, while 39 other sites are currently under some degree of active study or remediation. At December 31, 2001, Exelon had accrued $127 million for investigation and remediation of these MGP sites that currently can be reasonably estimated. Exelon believes that it could incur additional liabilities with respect to MGP sites, which cannot be reasonably estimated at this time. Exelon has sued a number of insurance carriers seeking indemnity/coverage for remediation costs associated with these former MGP sites. 30 AIR Air quality regulations promulgated by the EPA, the PDEP and the City of Philadelphia in accordance with the Federal Clean Air Act and the Clean Air Act Amendments of 1990 (Amendments) impose restrictions on emission of particulates, sulfur dioxide (SO2), nitrogen oxides (NOx) 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 NOx from electric power plants. Flue-gas desulfurization systems (scrubbers) have been installed at all of Generation's coal-fired units other than the Keystone Station. Keystone is subject to, and in compliance with, the Phase II SO2 and NOx limits of the Amendments, which became effective January 1, 2000. Generation and the other Keystone co-owners are purchasing SO2 emission allowances to comply with the Phase II limits. Generation has completed implementation of measures, including the installation of NOx emissions controls and the imposition of certain operational constraints, to comply with the Reasonably Available Control Technology limitations of the Amendments. Generation expects that the cost of compliance with anticipated air-quality regulations may be substantial due to further limitations on permitted NOx emissions. The EPA has issued two regulations to limit NOx emissions from power plants in the eastern United States to address the "ozone transport" issue. The first regulation was issued on September 24, 1998. The original NOx regulation covered power plants in the 22 eastern states and had an effective date of May 1, 2003. As a result of litigation at the D.C. Circuit Court of Appeals, the original NOx regulation was revised to cover 19 eastern states (rather than the original 22) and the effective date was delayed by approximately one year to May 31, 2004. In most other respects, the original NOx regulation was substantively upheld by the Court. Both Illinois and Pennsylvania power plants are covered by the original NOx regulation. The second EPA regulation, referred to as the "Section 126 Petition Regulation," was issued on May 25, 1999. This regulation was issued by the EPA in response to downwind state (Connecticut, Maine, Massachusetts, New Hampshire, New York, Pennsylvania, Rhode Island, Vermont) complaints under Section 126 of the Clean Air Act that upwind state NOx emissions were negatively impacting downwind states' ability to attain the Federal ozone standard. The Section 126 Petition Regulation requires substantively the same NOx reduction requirement for the power generation sector as the original NOx regulation. However, the Section 126 Petition Regulation covers a more limited number of states (Delaware, Indiana, Kentucky, Maryland, Michigan, North Carolina, New Jersey, New York, Ohio, Virginia and West Virginia). It does not cover power plants in Illinois. The compliance date of the Section 126 Petition Regulation, originally set for May 1, 2003, was tolled by the D.C. Circuit Court of Appeals pending resolution of several issues. Despite this delay, the northeast states covered by the Section 126 Petition Regulation are still expected to comply with the original May 1, 2003 compliance date. On September 23, 2000, Pennsylvania issued final state NOx reduction regulations for power plants that satisfy both the original NOx regulation and the Section 126 Petition Regulation. The Pennsylvania regulation is effective May 1, 2003. Exelon is currently evaluating options to comply with the new Pennsylvania regulations. These options include limiting the operation of the Generation's fossil-fired units, require the purchase of NOx emission allowances from the allowance market, the installation of additional control equipment, or a combination of these alternatives. 31 Many other provisions of the Amendments affect activities of Exelon's business, primarily Generation. The Amendments establish stringent control measures for geographical regions which have been determined by the EPA to not meet National Ambient Air Quality Standards; establish limits on the purchase and operation of motor vehicles and require increased use of alternative fuels; establish stringent controls on emissions of toxic air pollutants and provide for possible future designation of some utility emissions as toxic; establish new permit and monitoring requirements for sources of air emissions; and provide for significantly increased enforcement power, and civil and criminal penalties. Several other legislative and regulatory proposals regarding the control of emissions of air pollutants from a variety of sources, including utility units, are under active consideration. Exelon is unable at this time to ascertain which proposals may take effect, what requirements they may contain, or how they may affect Exelon's business. At this time, Exelon can provide no assurance that these proposals if adopted will not have a significant effect on Exelon's operations and costs. COSTS At December 31, 2001, Exelon accrued $156 million for various environmental investigation and remediation costs that can be reasonably estimated, including approximately $127 million for investigation and remediation of former MGP sites as described above. Exelon cannot currently predict whether it will incur other significant liabilities for additional investigation and remediation costs at sites presently identified or additional sites which may be identified by Exelon, environmental agencies or others or whether all such costs will be recoverable through rates or from third parties. Exelon's budget for capital requirements for 2002 for compliance with environmental requirements total approximately $35 million. In addition, Exelon may be required to make significant additional expenditures not presently determinable. OTHER SUBSIDIARIES OF COMED AND PECO WITH PUBLICLY HELD SECURITIES ComEd Transitional Funding Trust (ComEd Funding Trust), a Delaware business trust, was formed on October 28, 1998, pursuant to a trust agreement among First Union Trust Company, National Association, as Delaware trustee, and two individual trustees appointed by ComEd. ComEd Funding Trust was created for the sole purpose of issuing transitional funding notes to securitize intangible transition property granted to ComEd Funding LLC, a ComEd affiliate, by an ICC order issued July 21, 1998. On December 16, 1998, ComEd Funding Trust issued $3.4 billion of transitional funding notes, the proceeds of which were used to purchase the intangible transition property held by ComEd Funding LLC. ComEd Funding LLC transferred the proceeds to ComEd where they were used, among other things, to repurchase outstanding debt and equity securities of ComEd. The transitional funding notes are solely obligations of ComEd Funding Trust and are secured by the intangible transition property, which represents the right to receive instrument funding charges collected from ComEd's customers. The instrument funding charges represent a nonbypassable, usage-based, per kWh charge on designated consumers of electricity. ComEd Financing I, a Delaware business trust, was formed by ComEd on July 21, 1995. ComEd Financing I was created solely for the purpose of issuing $200 million of trust preferred securities. The trust preferred 32 securities issued on September 26, 1995, carry an annual distribution rate of 8.48% and are mandatorily redeemable on September 30, 2035. The sole assets of ComEd Financing I are $206.2 million principal amount of 8.48% subordinated deferrable interest notes due September 30, 2035, issued by ComEd. Similarly, ComEd Financing II, a Delaware business trust, was formed by ComEd on November 20, 1996. ComEd Financing II was created solely for the purpose of issuing $150 million of trust capital securities. The trust capital securities were issued on January 24, 1997, carry an annual distribution rate of 8.50% and are mandatorily redeemable on January 15, 2027. The sole assets of ComEd Financing II are $154.6 million principal amount of 8.50% subordinated deferrable interest debentures due January 15, 2027, issued by ComEd. PECO Energy Transition Trust (PETT), a Delaware business trust wholly owned by PECO, was formed on June 23, 1998 pursuant to a trust agreement between PECO, as grantor, First Union Trust Company, National Association, as issuer trustee, and two beneficiary trustees appointed by PECO. PETT was created for the sole purpose of issuing transition bonds to securitize a portion of PECO's authorized stranded cost recovery. On March 25, 1999, PETT issued $4 billion of its Series 1999-A Transition Bonds. On May 2, 2000, PETT issued $1 billion of its Series 2000-A Transition Bonds and on March 1, 2001, PETT issued $805 million of its Series 2001-A Transition Bonds to refinance a portion of the Series 1999-A Transition Bonds. The Transition Bonds are solely obligations of PETT secured by intangible transition property, representing the right to collect transition charges sufficient to pay the principal and interest on the Transition Bonds, sold by PECO to PETT. PECO Energy Capital Corp., a wholly owned subsidiary of PECO, is the sole general partner of PECO Energy Capital, L.P., a Delaware limited partnership (Partnership). The Partnership was created solely for the purpose of issuing preferred securities, representing limited partnership interests and lending the proceeds thereof to PECO and entering into similar financing arrangements. The loans to PECO are evidenced by PECO's subordinated debentures (Subordinated Debentures), which are the only assets of the Partnership. The only revenues of the Partnership are interest on the Subordinated Debentures. All of the operating expenses of the Partnership are paid by PECO Energy Capital Corp. As of December 31, 2001, the Partnership held $128 million aggregate principal amount of the Subordinated Debentures. PECO Energy Capital Trust II (Trust II) was created in June 1997 as a Delaware business trust solely for the purpose of issuing trust receipts (Trust II Receipts) each representing an 8.00% Cumulative Monthly Income Preferred Security, Series C (Series C Preferred Securities) of the Partnership. The Partnership is the sponsor of Trust II. As of December 31, 2001, Trust II had outstanding 2,000,000 Trust II Receipts. At December 31, 2001, the assets of Trust II consisted solely of 2,000,000 Series C Preferred Securities with an aggregate stated liquidation preference of $50 million. Distributions were made on the Trust II Receipts during 2001 in the aggregate amount of $4 million. Expenses of Trust II for 2001 were approximately $10,000, all of which were paid by PECO Energy Capital Corp. The Trust II Receipts are issued in book-entry only form. PECO Energy Capital Trust III (Trust III) was created in April 1998 as a Delaware business trust solely for the purpose of issuing trust receipts (Trust III Receipts) each representing an 7.38% Cumulative Preferred Security, Series D (Series D Preferred Securities) of the Partnership. The Partnership is the sponsor of Trust III. As of December 31, 2001, Trust III had outstanding 78,105 Trust III Receipts. At December 31, 2001, the assets of Trust III consisted solely of 78,105 Series D Preferred Securities with an aggregate stated liquidation preference of 33 $78 million. Distributions were made on Trust III Receipts during 2001 in the aggregate amount of $5.8 million. Expenses of Trust III for 2001 were approximately $10,000, all of which were paid by PECO Energy Capital Corp. The Trust III Receipts are issued in book-entry only form. EXECUTIVE OFFICERS OF THE REGISTRANTS AT DECEMBER 31, 2001 EXELON

Name Age Position -------------------------------------- --- ---------------------------------------------------------- McNeill, Jr., Corbin A. 62 Co-Chief Executive Officer and Chairman (retiring as of April 23, 2002) Rowe, John W. 56 Co-Chief Executive Officer and President Kingsley Jr., Oliver D. 59 Executive Vice President Strobel, Pamela B. 49 Executive Vice President Clark, Frank M. 56 Senior Vice President Gillis, Ruth Ann M. 47 Senior Vice President and Chief Financial Officer Gilmore Jr., George H. 52 Senior Vice President Lawrence, Kenneth G. 54 President and Chief Operating Officer, Energy Delivery McLean, Ian P. 52 Senior Vice President Mehrberg, Randall E. 46 Senior Vice President and General Counsel Moler, Elizabeth A. 52 Senior Vice President, Government Affairs and Policy Padron, Honorio J. 49 Senior Vice President Snodgrass, S. Gary 50 Senior Vice President and Chief Human Resources Officer Gibson, Jean 45 Vice President and Corporate Controller

34 ComEd

Name Age Position -------------------------------------- --- ---------------------------------------------------------------------------------- McNeill, Jr., Corbin A. 62 Co-Chief Executive Officer and Chairman, Exelon and Director, ComEd (retiring as of April 23, 2002) Rowe, John W. 56 Co-Chief Executive Officer and President, Exelon and Director, ComEd Strobel, Pamela B. 49 Executive Vice President, Exelon and Chair, ComEd Gillis, Ruth Ann M. 47 Senior Vice President, Finance and Chief Financial Officer, Exelon and Director, ComEd Lawrence, Kenneth G. 54 President and Chief Operating Officer, Energy Delivery and Director, ComEd Clark, Frank M. 56 President, ComEd Helwig, David R. 51 Executive Vice President, Operations, ComEd Berdelle, Robert E. 45 Vice President, Finance and Chief Financial Officer, ComEd

PECO

Name Age Position -------------------------------------- --- ---------------------------------------------------------------------------------- McNeill, Jr., Corbin A. 62 Co-Chief Executive Officer and Chairman, Exelon and Director, PECO (retiring as of April 23, 2002) Rowe, John W. 56 Co-Chief Executive Officer and President, Exelon and Director, PECO Strobel, Pamela B. 49 Executive Vice President, Exelon and Chair, PECO Gillis, Ruth Ann M. 47 Senior Vice President and Chief Financial Officer, Exelon and Director, PECO Lawrence, Kenneth G. 54 President, PECO Frankowski, Frank F. 51 Vice President, Finance and Chief Financial Officer, PECO

Each of the above was elected as an executive officer effective October 20, 2000, the closing date of the merger, except for Randall E. Mehrberg, who was elected effective December 1, 2000, Robert E. Berdelle, who was elected effective October 11, 2001, Frank F. Frankowski, who was elected effective October 22, 2001 and George H. Gilmore, Jr., who was elected effective December 3, 2001. 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 current position, Mr. McNeill was Co-Chief Executive Officer of ComEd and President, Co-Chief Executive Officer and Chairman of PECO; Chief Executive Officer of PECO; Chief Operating Officer and Executive Vice President, Nuclear division of PECO. Prior to his election to his current position, Mr. Rowe was President, Co-Chief Executive Officer of ComEd and President, Co-Chief Executive Officer of PECO; Chairman, President and Chief Executive Officer of ComEd and Unicom; and President and Chief Executive Officer of New England Electric System. Prior to his election to his current position, Mr. Kingsley was Executive Vice President of ComEd and Unicom, President and Chief Nuclear Officer, Nuclear Generation Group of ComEd, and Chief Nuclear Officer of the Tennessee Valley Authority. Prior to her election to her current position, Ms. Strobel was Vice Chairman of ComEd; Vice Chairman of PECO; Executive Vice President and General Counsel of ComEd and Unicom; Senior Vice President and General Counsel of ComEd and Unicom; and Vice President and General Counsel of ComEd. Prior to his election to his current position, Mr. Clark was Senior Vice President, Distribution Customer and Marketing Services and External Affairs of ComEd; Senior Vice President of ComEd and Unicom; Vice President of ComEd; Governmental Affairs Vice President; and Governmental Affairs Manager. Prior to her election to her current position, Ms. Gillis was Senior Vice President and Chief Financial Officer of ComEd and Unicom; Vice President and Treasurer of ComEd and Unicom; Vice President, Chief Financial Officer and Treasurer of the University of Chicago Hospitals and Health System; and Senior Vice President and Chief Financial Officer of American National Bank and Trust Company. Prior to his election to his current position, Mr. Gilmore was Group President for National Service Industries, Inc.; President and Chief Operating Officer of Calmat Company; and President of Moore Document Solutions and Moore Business Systems. Prior to his election to his current position, Mr. Lawrence was Senior Vice President, Distribution of PECO; Senior Vice President of PECO, President, Distribution division, of PECO; Senior Vice President, Distribution division of PECO; Senior Vice President, Finance and Chief Financial Officer of PECO; and Vice President, Gas Operations division of PECO. Prior to his election to his current position, Mr. McLean was President of the Power Team division of PECO; and Group Vice President of Engelhard Corporation. 35 Prior to his election to his current position, Mr. Mehrberg was an equity partner with the law firm of Jenner & Block; and General Counsel and Lakefront Director of the Chicago Park District. Prior to her election to her current position, Ms. Moler was Senior Vice President of ComEd and Unicom; Director of Unicom and ComEd; Partner at the law firm of Vinson & Elkins, LLP; Deputy Secretary of the U.S. Department of Energy; and Chair of the Federal Energy Regulatory Commission. Prior to his election to his current position, Mr. Padron was Executive Vice President Process Engineering and Chief Information Officer of CompUSA, Inc.; Senior Vice President and Chief Information Officer of Pepsico Restaurant Service Group; and Senior Vice President Business Engineering and Technology and Chief Information Officer of Flagstar Corporation. Prior to his election to his current position, Mr. Snodgrass was Senior Vice President of ComEd and Unicom; Vice President of ComEd and Unicom; and Vice President of USG Corporation. Prior to her election to her current position, Ms. Gibson was Vice President and Controller of PECO; and Director of Audit Services and Director of the Tax Division of PECO. Prior to his election to his current position, Mr. Helwig was Senior Vice President, Operations of ComEd; Senior Vice President of ComEd; Vice President of ComEd; General Manager of General Electric Company's Nuclear Services Company; and Vice President at PECO. Prior to his election to his current position, Mr. Berdelle was Vice President and Comptroller of Unicom and ComEd; and Manager of Financial Reporting of Unicom and ComEd. Prior to his election to his current position of Vice President, Finance and Chief Financial Officer of PECO Energy Company, Mr. Frankowski was Controller of PECO Energy Company; Manager, Accounting and Control of PECO Energy; and Director - Taxes of PECO Energy Company. 36 ITEM 2. PROPERTIES. ENERGY DELIVERY The electric substations and a portion of the transmission rights of way of ComEd and PECO are owned in fee. A significant portion of the electric transmission and distribution facilities is located over or under highways, streets, other public places or property owned by others, for which permits, grants, easements or licenses, deemed satisfactory by ComEd and PECO, respectively, but without examination of underlying land titles, have been obtained. TRANSMISSION AND DISTRIBUTION Exelon's higher voltage electric transmission and distribution lines owned and in service are as follows:

Voltage (Volts) Circuit Miles ---------------- -------------- ComEd 765,000 90 345,000 2,590 138,000 2,110 PECO 500,000 891 220,000 1,634 132,000 15

ComEd's electric distribution system includes 40,633 pole-line miles of overhead lines and 38,798 cable miles of underground lines. PECO's electric distribution system includes 21,009 pole-line miles of overhead lines and 21,002 cable miles of underground lines. GAS The following table sets forth PECO's gas pipeline miles at December 31, 2001:

Pipeline Miles --------------- Transmission 31 Distribution 6,199 Service piping 5,171 ------ Total 11,401 ======

PECO has a liquefied natural gas facility located in West Conshohocken, Pennsylvania that has a storage capacity of 1,200,000 million cubic feet (mcf) and a sendout capacity of 157,000 mcf/day and a propane-air plant located in Chester, Pennsylvania, with a tank storage capacity of 1,980,000 gallons and a peaking capability of 25,000 mcf/day. In addition, PECO owns 28 natural gas city gate stations at various locations throughout its gas service territory. 37 MORTGAGES The principal plants and properties of ComEd are subject to the lien of ComEd's Mortgage dated July 1, 1923, as amended and supplemented, under which ComEd's first mortgage bonds are issued. The principal plants and properties of PECO are subject to the lien of PECO's Mortgage dated May 1, 1923, as amended and supplemented, under which PECO's first mortgage bonds are issued. 38 GENERATION The following table sets forth Generation's owned net electric generating capacity by station at December 31, 2001:

No. of % Primary Dispatch Net Generation Station Location Units Owned (1) Fuel Type Type Capacity(MW) (2) --------- -------- ------ ------- --------- -------- -------------- Nuclear (3) Braidwood Braidwood, IL 2 Uranium Base-load 2,372 Byron Byron, IL 2 Uranium Base-load 2,391 Dresden Morris, IL 2 Uranium Base-load 1,659 LaSalle County Seneca, IL 2 Uranium Base-load 2,298 Limerick Limerick Twp., PA 2 Uranium Base-load 2,312 Peach Bottom Peach Bottom Twp., PA 2 50.00 Uranium Base-load 1,112 (4) Quad Cities Cordova, IL 2 75.00 Uranium Base-load 1,172 (4) Salem Hancock's Bridge, NJ 2 42.59 Uranium Base-load 934 (4) ------- 14,250 Fossil (Steam Turbines) Cromby (1) Phoenixville, PA 1 Coal Base-load 144 Cromby (2) Phoenixville, PA 1 Oil/Gas Intermediate 201 Delaware Philadelphia, PA 2 Oil Peaking 250 Eddystone (1), (2) Eddystone, PA 2 Coal Base-load 581 Eddystone (3), (4) Eddystone, PA 2 Oil/Gas Intermediate 760 Schuylkill Philadelphia, PA 1 Oil Peaking 166 Conemaugh New Florence, PA 2 20.72 Coal Base-load 352 (4) Keystone Shelocta, PA 2 20.99 Coal Base-load 357 (4) Fairless Hills Falls Twp., PA 2 Landfill Gas Peaking 60 ------- 2,871 Fossil (Combustion Turbines) Chester Chester, PA 3 Oil Peaking 39 Croydon Bristol Twp., PA 8 Oil Peaking 380 Delaware Philadelphia, PA 4 Oil Peaking 56 Eddystone Eddystone, PA 4 Oil Peaking 60 Falls Falls Twp., PA 3 Oil Peaking 51 Moser Lower Pottsgrove Twp., PA 3 Oil Peaking 51 Pennsbury Falls Twp., PA 2 Landfill Gas Peaking 6 Richmond Philadelphia, PA 2 Oil Peaking 96 Schuylkill Philadelphia, PA 2 Oil Peaking 30 Southwark Philadelphia, PA 4 Oil Peaking 52 Salem Hancock's Bridge, NJ 1 42.59 Oil Peaking 16 (4) LaPorte LaPorte, Tx 4 Gas Peaking 160 ------- 997 Fossil (Internal Combustion/Diesel) Cromby Phoenixville, PA 1 Oil Peaking 3 Delaware Philadelphia, PA 1 Oil Peaking 3 Schuylkill Philadelphia, PA 1 Oil Peaking 3 Conemaugh New Florence, PA 4 20.72 Oil Peaking 2 (4) Keystone Shelocta, PA 4 20.99 Oil Peaking 2 (4) ------- 13 Hydroelectric Conowingo Harford Co., MD 11 Hydro Base-load 512 Muddy Run Lancaster Co., PA 8 Hydro Intermediate 1,072 --- ------- 1,584 ------- 101 19,715 === =======

(1) 100%, unless otherwise indicated. (2) For nuclear stations, except Salem, capacity reflects the annual mean rating. All other stations, including Salem, reflect a summer rating. (3) All nuclear stations are boiling water reactors except Braidwood, Byron and Salem, which are pressurized water reactors. (4) Generation's portion. 39 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. Exelon and its subsidiaries maintain property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For information regarding nuclear insurance, see ITEM 1. Business - Generation. Exelon and its subsidiaries are self-insured to the extent that any losses may exceed the amount of insurance maintained. Any such losses could have a material adverse effect on Exelon's consolidated financial condition and results of operations. ITEM 3. LEGAL PROCEEDINGS. EXELON During 1989 and 1991, actions were brought in Federal and state courts in Colorado against ComEd and its subsidiary, Cotter Corporation (Cotter), seeking unspecified damages and injunctive relief based on allegations that Cotter permitted radioactive and other hazardous material to be released from its mill into areas owned or occupied by the plaintiffs, resulting in property damage and potential adverse health effects. In 1994, a Federal jury returned nominal dollar verdicts against Cotter on eight plaintiffs' claims in the 1989 cases, which verdicts were upheld on appeal. The remaining claims in the 1989 actions were settled or dismissed. In 1998, a jury verdict was rendered against Cotter in favor of 14 of the plaintiffs in the 1991 cases, totaling approximately $6 million in compensatory and punitive damages, interest and medical monitoring. On appeal, the Tenth Circuit Court of Appeals reversed the jury verdict, and remanded the case for new trial. These plaintiffs' cases were consolidated with the remaining 26 plaintiffs' cases, which had not been tried. The consolidated trial was completed on June 28, 2001. The jury returned a verdict against Cotter and awarded $16 million in various damages. On November 20, 2001, the District Court entered an amended final judgment which included an award of both pre-judgment and post-judgment interests, costs, and medical monitoring expenses which total $43 million. This matter is being appealed by Cotter in the Tenth Circuit Court of Appeals. Cotter will vigorously contest the award. In November 2000, another trial involving a separate sub-group of 13 plaintiffs, seeking $19 million in damages plus interest was completed in federal district court in Denver. The jury awarded nominal damages of $42,500 to 11 of 13 plaintiffs, but awarded no damages for any personal injury or health claims, other than requiring Cotter to perform periodic medical monitoring at minimal cost. The plaintiffs appealed the verdict to the Tenth Circuit Court of Appeals. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability incurred by Cotter as a result of these actions, as well as any liability arising in connection with the West Lake Landfill discussed in the next paragraph. In connection with the corporate restructuring, the responsibility to indemnify Cotter for any liability related to these matters was transferred to Generation. Generation's management believes adequate reserves have been established in connection with these proceedings. 40 The United States Environmental Protection Agency (EPA) has advised Cotter that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached barium sulfate at the site. Cotter, along with three other companies identified by the EPA as potentially responsible parties (PRPs), is reviewing a draft feasibility study that recommends capping the site. The PRPs are also engaged in discussions with the State of Missouri and the EPA. The estimated costs of remediation for the site are $10 to $15 million. Once a final feasibility study is complete and a remedy selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. Until an agreement is reached, Generation cannot predict its share of the costs. PECO initiated tax appeals regarding two of its nuclear facilities, Limerick Generating Station (Montgomery County) and Peach Bottom Atomic Power Station (York County), and one of its fossil facilities, Eddystone (Delaware County). The potential benefit or obligation resulting from these appeals was transferred to Generation in connection with the corporate restructuring. Generation is also involved in a tax appeal for TMI (Dauphin County) through AmerGen. Generation does not believe the outcome of these matters will have a material adverse effect on its results of operations or financial condition. On May 27, 1998, the United States Department of Justice, on behalf of the Rural Utilities Service and the Chapter 11 Trustee for the Cajun Electric Power Cooperative, Inc. ("Cajun"), filed an action claiming breach of contract against PECO in the United States District Court for the Middle District of Louisiana arising out of PECO's termination of the contract to purchase Cajun's interest in the River Bend nuclear power plant. Effective with the corporate restructuring, Generation has agreed to assume any liability and obligation arising from this litigation. During 2001, the parties reached a settlement of the dispute, and Generation made a payment of $14 million to Cajun. Generation is an unsecured creditor in Enron Corp.'s (Enron) bankruptcy proceeding. Generation's claim for power and other products sold to Enron in November and early December 2001 is $8.5 million. Enron may assert that Generation should not have closed out and terminated all of its forward contracts with Enron. If Enron is successful in this argument, Generation's exposure could be greater than $8.5 million. Generation may also be subject to exposure due to the credit policies of ISO-operated spot markets that allocate defaults of market participants to non-defaulting participants. Generation has established reserves for these matters. (See the ComEd litigation section for additional Enron litigation matters.) COMED In March 1999, ComEd reached a settlement agreement with the City of Chicago (Chicago) to end the arbitration proceeding between ComEd and Chicago regarding the January 1, 1992 franchise agreement. As part of the settlement agreement, ComEd and Chicago agreed to a revised combination of ongoing work under the franchise agreement and new initiatives that total approximately $1 billion in defined transmission and distribution expenditures by ComEd to improve electric services in Chicago, of which approximately $940 million has been expended through December 31, 2001. The settlement agreement provides that ComEd would be subject to liquidated damages if the projects are not completed by various dates, unless it was prevented from doing so by events beyond its reasonable control. In addition, ComEd and Chicago established an Energy Reliability and Capacity Account, into which ComEd deposited $25 million during each of the years 1999 through 2001 and has conditionally agreed to deposit $25 million at the end of 2002, to help ensure an adequate and reliable electric supply for Chicago. 41 Three of ComEd's wholesale municipal customers filed a complaint and request for refund with the FERC alleging that ComEd failed to properly adjust its rates, as provided for under the terms of the electric service contracts with the municipal customers and to track certain refunds made to ComEd's retail customers in the years 1992 through 1994. In the third quarter of 1998, FERC granted the complaint and directed that refunds be made, with interest. ComEd filed a request for rehearing. On April 30, 2001, FERC issued an order granting rehearing in which it determined that its 1998 order had been erroneous and that no refunds were due from ComEd to the municipal customers. On June 29, 2001, FERC denied the customers' requests for rehearing of the order granting rehearing. In August 2001, each of the three wholesale municipal customers appealed the April 30, 2001 FERC order to the Federal circuit court, which consolidated the appeals for the purposes of briefing and decision. In November 2001, the court suspended briefing pending court-initiated settlement discussions. On April 18, 2001, the Godley Park District filed suit in Will County Circuit Court against ComEd and Exelon alleging that oil spills at Braidwood Station have contaminated the Park District's water supply. The complaint sought actual damages, punitive damages of $100 million and statutory penalties. The court dismissed all counts seeking punitive damages and statutory penalties, and the plaintiff has filed an amended complaint before the court. ComEd is contesting the liability and damages sought by the plaintiff. In 1996, several developers of non-utility generating facilities filed litigation against various Illinois officials claiming that the enforcement against those facilities of an amendment to Illinois law removing the entitlement of those facilities to state-subsidized payments for electricity sold to ComEd after March 15, 1996 violated their rights under the Federal and state constitutions. The developers also filed suit against ComEd for a declaratory judgement that their rights under their contracts with ComEd were not affected by the amendment. On August 4, 1999, the Illinois Appellate Court held that the developers' claims against the state were premature, and the Illinois Supreme Court denied leave to appeal that ruling. Developers of both facilities have since filed amended complaints repeating their allegations that ComEd breached the contracts in question and requesting damages for such breach, in the amount of the difference between the state-subsidized rate and the amount ComEd was willing to pay for the electricity. ComEd is contesting this matter. In August 1999, three class action lawsuits were filed against ComEd, and subsequently consolidated, in the Circuit Court of Cook County, Illinois seeking damages for personal injuries, property damage and economic losses related to a series of service interruptions that occurred in the summer of 1999. The combined effect of these interruptions resulted in over 168,000 customers losing service for more than four hours. Conditional class certification was approved by the court for the sole purpose of exploring settlement talks. ComEd filed a motion to dismiss the complaints. On April 24, 2001, the court dismissed four of the five counts of the consolidated complaint without prejudice and the sole remaining count was dismissed in part. On June 1, 2001, the plaintiffs filed a second amended consolidated complaint and ComEd has filed an answer. A portion of any settlement or verdict may be covered by insurance; discussions with the carrier are ongoing. ComEd's management believes adequate reserves have been established in connection with these cases. As a result of Enron's bankruptcy proceeding, ComEd has potential monetary exposure for customers served by Enron Energy Services (EES) as a billing agent. On January 7, 2002, EES was authorized by the bankruptcy court to, and subsequently did, reject its contract with 129 of ComEd's customer accounts. As of March 15, 2002, EES was the billing agent for 97 of 42 ComEd's customer accounts. EES has advised Exelon that it will retain its billing agency with these remaining accounts. ComEd is working to ensure that customers know what amounts are owed to ComEd on 269 accounts on which EES has been removed as billing agent, and has obtained updated billing addresses for these accounts. With regard to the 97 remaining accounts, as of March 15, 2002, ComEd's total amount outstanding is immaterial. Because that amount is owed to ComEd by individual customers, it is not part of the bankrupt Enron's estate. The ICC has rescinded EES's authority to act as an alternative retail energy supplier in Illinois. However, EES never served as a supplier, as opposed to a billing agent, to any of ComEd's retail accounts. PECO None. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. None. 43 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. EXELON The information required by this Item with respect to market information relating to Exelon's common stock is incorporated herein by reference to "Market for Registrant's Common Equity and Related Stockholder Matters" in Exhibit 99-1 to Exelon's Current Report on Form 8-K dated February 28, 2002. ComEd As of March 1, 2002, there were outstanding 127,016,373 shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were held by Exelon. At March 1, 2002, in addition to Exelon, there were approximately 280 holders of ComEd common stock. There is no established market for shares of the common stock of ComEd. ComEd may not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities which were issued to ComEd Financing I and ComEd Financing II (the Financing Trusts); (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of the Financing Trusts; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. See Item 1. Business - Other Subsidiaries of ComEd and PECO with Publicly Held Securities. PECO As of March 1, 2002, there were outstanding 170,478,507 shares of common stock, without par value, of PECO, all of which were held by Exelon. PECO's Articles of Incorporation prohibit payment of any dividend on, or other distribution to the holders of, common stock if, after giving effect thereto, the capital of PECO represented by its common stock together with its retained earnings is, in the aggregate, less than the involuntary liquidating value of its then outstanding preferred stock. At December 31, 2001, such capital ($2.2 billion) amounted to about 14 times the liquidating value of the outstanding preferred stock ($156 million). PECO may not declare dividends on any shares of its capital stock in the event that: (1) PECO exercises its right to extend the interest payment periods on the Subordinated Debentures which were issued to the Partnership; (2) PECO defaults on its guarantee of the payment of distributions on the Series C or Series D Preferred Securities of the Partnership; or (3) an event of default occurs under the Indenture under which the Subordinated Debentures are issued. See Item 1. Business - Other Subsidiaries of ComEd and PECO with Publicly Held Securities. DIVIDENDS Under PUHCA and the Federal Power Act, Exelon, ComEd, PECO and Generation can only pay dividends from retained or current earnings. Similar restrictions also apply to ComEd 44 under the Illinois Public Utilities Act. An SEC order issued under PUHCA granted permission to Exelon and ComEd to pay up to $500 million in dividends out of additional paid-in capital, provided that Exelon agreed not to pay dividends out of paid-in capital after December 31, 2002 if its common equity is less than 30% of its total capitalization. At December 31, 2001, Exelon had retained earnings of $1.2 billion, which includes ComEd retained earnings of $257 million, PECO retained earnings of $270 million and Generation retained earnings of $471 million. The following table sets forth Exelon's quarterly cash dividends paid during 2001 and 2000:

2001 2000 ---------------------------------------- ---------------------------------------- 1st 2nd 3rd 4th 1st 2nd 3rd 4th (per share) Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter ----------- ------- ------- ------- ------- -------- -------- ------- ------- Exelon $ 0.55 (1) $ 0.42 $ 0.42 $ 0.43 $ 0.25 $ 0.25 $ 0.25 $ 0.16 ------- ------- ------- -------- -------- ------- ------- -------

(1) Exelon did not pay any cash dividends in 2000. The first quarter dividend in 2001 was a pro rata dividend. Unicom and PECO each paid their shareholders pro rata, per diem dividends from their last regular dividend dates through October 19, 2000. The first quarter of 2001 covered the 119-day period from the date of the Merger, through the February 15, 2001 record date. The following table sets forth ComEd and PECO's quarterly common dividend payments:

2001 2000 ---------------------------------------- ---------------------------------------- 1st 2nd 3rd 4th 1st 2nd 3rd 4th (in millions) Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter ------------- -------- ------- ------- ------- ------- ------- ------- ------- ComEd $ 63 $ 85 $ 105 $ 230 $ 87 $ 75 $ 74 $ 90 PECO $ 45 $ 55 $ 69 $ 173 $ 45 $ 43 $ 43 $ 26 -------- ------- ------- ------- ------- ------- ------- -------

On January 29, 2002, the Board of Directors of Exelon declared a quarterly dividend of $0.44 per share of Exelon's common stock. This increase of $0.07 per share annually will result in an annual dividend rate of $1.76 per share. The new dividend rate reflects Exelon's vertically integrated business portfolio and its focus on total return to shareholders. The new dividend rate represents about a 50% payout of the expected 2002 earnings per share from Exelon's regulated electricity delivery businesses. Exelon intends to grow the dividend to about a 60% payout of earnings from regulated operations based on cash flow and earnings growth prospects for Energy Delivery. The payment of future dividends is subject to approval and declaration by the Board of Directors each quarter. ITEM 6. SELECTED FINANCIAL DATA. EXELON The information required by this Item is incorporated herein by reference to "Selected Financial Data" in Exhibit 99-1 to Exelon's Current Report on Form 8-K dated February 28, 2002. 45 COMED The selected consolidated financial data presented below has been derived from the audited financial statements of ComEd. This data is qualified in its entirety by reference to, and should be read in conjunction with ComEd's Consolidated Financial Statements and Management's Discussion and Analysis of Financial Condition and Results of Operations included herein. The information for the year ended 2000 is presented for the periods before and after the Merger. For additional information, see ITEM 8. Financial Statements and Supplementary Data - ComEd, Notes 1 and 3 of the Notes to Consolidated Financial Statements.

Jan. 1 - Oct. 20 - Jan. 1 - Dec. 31 Dec. 31 Oct. 19 For the Years Ended December 31, -------------------------------- (in millions) 2001 2000 2000 1999 1998 1997 ------------- ------ ------ ------ ------- ------- ------- STATEMENT OF INCOME DATA: Operating Revenues $ 6,206 $ 1,310 $ 5,702 $ 6,793 $ 7,150 $ 7,076 Operating Income 1,594 338 1,048 1,549 1,387 1,214 Income (Loss) before Extraordinary Items And Cumulative Effect of a Change in Accounting Principle 607 133 603 651 594 (160) Extraordinary Item (net of income taxes) -- -- (4) (28) -- (810) Cumulative Effect of a Change in Accounting Principle (net of income taxes) -- -- -- -- -- 196 Net Income (Loss) on Common Stock 607 133 596 599 537 (834)

at December 31, ------------------------------------------------ (in millions) 2001 2000 1999 1998 1997 ------------- ------- ------ ------- ------- ------- BALANCE SHEET DATA: Current Assets $ 1,114 $ 2,172 $ 4,045 $ 4,974 $ 1,745 Property, Plant and Equipment, net 7,351 7,657 11,993 13,300 16,622 Deferred Debits and Other Assets 7,251 10,369 6,538 6,583 3,397 ------- ------- ------- ------- ------- Total Assets $15,716 $20,198 $22,576 $24,857 $21,764 ======= ======= ======= ======= ======= Current Liabilities $ 1,886 $ 1,723 $ 3,427 $ 3,309 $ 2,223 Long-Term Debt 5,850 6,882 6,962 7,677 5,563 Deferred Credits and Other Liabilities 2,568 5,082 6,456 7,770 8,050 Mandatorily Redeemable Preference Stock -- -- 69 171 205 Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding the Company's Subordinated Debt Securities 329 328 350 350 350 Shareholders' Equity 5,083 6,183 5,312 5,580 5,373 ------- ------- ------- ------- ------- Total Liabilities and Shareholders' Equity $15,716 $20,198 $22,576 $24,857 $21,764 ======= ======= ======= ======= =======

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

For the Years Ended December 31, ---------------------------------------------------- (in millions) 2001 2000 1999 1998 1997 ------------- -------- ------- ------- ------- -------- STATEMENT OF INCOME DATA: Operating Revenues $ 3,965 $ 5,950 $ 5,478 $ 5,325 $ 4,601 Operating Income 999 1,222 1,373 1,268 1,006 Income before Extraordinary Items and Cumulative Effect of a Change in Accounting Principle 425 487 619 533 337 Extraordinary Items (net of income taxes) -- (4) (37) (20) (1,834) Cumulative Effect of a Change in Accounting Principle (net of income taxes) -- 24 -- -- -- Net Income (Loss) on Common Stock 415 497 570 500 (1,514)

at December 31, -------------------------------------------------- (in millions) 2001 2000 1999 1998 1997 ------------- -------- ------- ------- ------- -------- BALANCE SHEET DATA: Current Assets $ 820 $ 1,779 $ 1,221 $ 582 $ 1,003 Property, Plant and Equipment, net 4,047 5,158 5,004 4,804 4,671 Deferred Debits and Other Assets 5,878 7,839 6,862 6,662 6,683 ------- ------- ------- ------- -------- Total Assets $10,745 $14,776 $13,087 $12,048 $12,357 ======= ======= ======= ======= ======= Current Liabilities $ 1,342 $ 2,974 $ 1,286 $ 1,735 $ 1,619 Long-Term Debt 5,438 6,002 5,969 2,920 3,853 Deferred Credits and Other Liabilities 3,358 3,860 3,738 3,756 3,576 Company-Obligated Mandatorily Redeemable Preferred Securities 128 128 128 349 352 Mandatorily Redeemable Preferred Stock 19 37 56 93 93 Shareholders' Equity 460 1,775 1,910 3,195 2,864 ------- ------- ------- ------- ------- Total Liabilities and Shareholders' Equity $10,745 $14,776 $13,087 $12,048 $12,357 ======= ======= ======= ======= ========

47 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS EXELON The information required by this Item is incorporated herein by reference to "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Exhibit 99-2 to Exelon's Current Report on Form 8-K dated February 28, 2002. COMED GENERAL On October 20, 2000, ComEd became a 99.9% owned subsidiary of Exelon as a result of the transactions relating to the Merger. As a result of the Merger, ComEd's consolidated financial information for the period after the Merger has a different cost basis than that of previous periods. Material variances caused by the different cost basis have been disclosed where applicable. Through December 31, 2000, ComEd operated as a vertically integrated electric utility. During January 2001, Exelon undertook a restructuring to separate its generation and other competitive businesses from its regulated energy delivery business. As part of the restructuring, the non-regulated operations and related assets and liabilities of ComEd were transferred to separate subsidiaries of Exelon. As a result, beginning January 2001, the operations of ComEd consist of its retail electricity distribution and transmission business in northern Illinois. The restructuring has had a significant impact on all components of ComEd's results of operations. The estimated impact of the restructuring set forth herein reflects the effects of removing the operations related to ComEd's nuclear generating stations and obtaining energy and capacity from Generation under the terms of the PPA for the year ended December 31, 2000. 48 RESULTS OF OPERATIONS YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000 SUMMARY FINANCIAL INFORMATION - COMED

Components of Variance ------------------------------------ Restructuring Normal (in millions) 2001 2000 Impact Operations Total -------------------------------------- ------- ------- -------------- ---------- ------- Operating Revenues $ 6,206 $ 7,012 $ (707) $ (99) $ (806) Fuel and Purchased Power 2,670 1,977 677 16 693 Operating and Maintenance 981 2,076 (1,072) (23) (1,095) Merger-Related Costs -- 67 -- (67) (67) Depreciation and Amortization 665 998 (282) (51) (333) Taxes Other Than Income 296 508 (131) (81) (212) ------- ------- ------- ------- ------- Total Operating Expenses 4,612 5,626 (808) (206) (1,014) ------- ------- ------- ------- ------- Operating Income 1,594 1,386 101 107 208 ------- ------- ------- ------- ------- Interest Expense (565) (596) 43 (12) 31 Distributions on Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely the Company's Subordinated Debt Securities (30) (30) -- -- -- Other, Net 114 308 -- (194) (194) ------- ------- ------- ------- ------- Income Before Income Taxes and Extraordinary Items 1,113 1,068 144 (99) 45 Income Taxes 506 332 72 102 174 ------- ------- ------- ------- ------- Net Income Before Extraordinary Items 607 736 72 (201) (129) Extraordinary Items (net of income taxes) -- (4) -- 4 4 Net Income 607 732 72 (197) (125) Preferred and Preference Stock Dividends -- (3) -- 3 3 ------- ------- ------- ------- ------- Net Income on Common Stock $ 607 $ 729 $ 72 $ (194) $ (122) ======= ======= ======= ======= =======

NET INCOME Net income from normal operations decreased $197 million, or 25% in 2001. Net income was impacted by $107 million in increased operating income offset by a higher effective tax rate and a $194 million decrease in other income and deductions primarily attributable to a gain on the forward share purchase arrangement recognized during 2000 and a reduction in intercompany interest income in 2001 as compared to 2000. 49 OPERATING REVENUES Bundled service reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and distribution of the energy. Unbundled service reflects customers electing to receive electric generation service from the PPO or an ARES. Revenue from customers choosing the PPO includes an energy charge at market rates, transmission and distribution charges and a CTC charge. Revenue from customers choosing an ARES includes a distribution charge and a CTC charge. Transmission charges received from ARES are included in wholesale and miscellaneous revenue. ComEd's electric sales statistics are as follows:

Retail Deliveries - (in megawatthours (MWh)) 2001 2000 Variance ---------- ---------- ---------- BUNDLED DELIVERIES Residential 25,281,880 23,997,261 1,284,619 Small Commercial & Industrial 23,435,141 24,832,551 (1,397,410) Large Commercial & Industrial 10,305,130 15,348,098 (5,042,968) Public Authorities & Electric Railroads 7,879,260 7,664,309 214,951 ---------- ---------- ---------- 66,901,411 71,842,219 (4,940,808) ========== ========== ========== UNBUNDLED DELIVERIES Small Commercial & Industrial - PPO 3,279,491 1,433,337 1,846,154 - ARES 2,865,423 2,772,316 93,107 Large Commercial & Industrial - PPO 5,749,995 2,812,524 2,937,471 - ARES 5,457,847 5,806,535 (348,688) Public Authorities & Electric Railroads - PPO 986,756 1,087,524 (100,768) - ARES 364,998 297,048 67,950 ---------- ---------- ---------- 18,704,510 14,209,284 4,495,226 ---------- ---------- ---------- TOTAL RETAIL DELIVERIES 85,605,921 86,051,503 (445,582) ========== ========== ========== Electric Revenue (in millions) 2001 2000 Variance ---------- ---------- ---------- BUNDLED REVENUE Residential $ 2,308 $ 2,235 $ 73 Small Commercial & Industrial 1,821 1,949 (128) Large Commercial & Industrial 523 811 (288) Public Authorities & Electric Railroads 430 424 6 ---------- ---------- ---------- 5,082 5,419 (337) ---------- ---------- ---------- UNBUNDLED REVENUE Small Commercial & Industrial- PPO 220 92 128 - ARES 48 62 (14) Large Commercial & Industrial - PPO 343 158 185 - ARES 74 115 (41) Public Authorities & Electric Railroads - PPO 59 56 3 - ARES 5 7 (2) ---------- ---------- ---------- 749 490 259 ---------- ---------- ---------- TOTAL ELECTRIC RETAIL REVENUES $ 5,831 $ 5,909 $ (78) Wholesale and Miscellaneous Revenue 375 396 (a) (21) ---------- ---------- ---------- TOTAL ELECTRIC REVENUE $ 6,206 $ 6,305 $ (99) ========== ========== ==========

(a) Includes the operations of ComEd as if the restructuring had occurred on January 1, 2000. 50 The changes in electric retail revenues for 2001, as compared to 2000, are attributable to the following:

(in millions) Variance -------- Customer Choice $(145) Weather 103 Revenue Taxes (88) Other Effects 76 Rate Changes (24) ----- Electric Retail Revenue $ (78) -----

o Customer Choice. ComEd non-residential customers have the choice to purchase energy from other suppliers. This choice generally does not impact MWh deliveries, but affects revenue collected from customers related to energy supplied by ComEd. The decrease in revenues reflects customers in Illinois electing to purchase energy from an ARES or the PPO. As of December 31, 2001, approximately 18,700 retail customers, representing 22% of total annual retail deliveries, had elected to purchase energy from the PPO or an ARES, compared to approximately 9,500 customers, representing 17% of total annual retail deliveries, as of December 31, 2000. o Weather. The demand for electricity and gas services is impacted by weather conditions. Very warm weather in summer months and very cold weather in other months is referred to as "favorable weather conditions", because these weather conditions result in increased demand for electricity. Conversely, mild weather reduces demand. Although weather was moderate in 2001, the weather impact was favorable compared to the prior year as a result of warmer summer weather offset in part by warmer winter weather in 2001. Cooling degree days increased 11% in 2001 compared to 2000 while heating degree days decreased 5% in 2001 compared to 2000. o Revenue taxes. The change in revenue taxes represents a change in presentation of certain revenue taxes from operating revenue and tax expense to collections recorded as liabilities resulting from Illinois legislation. This change in presentation does not affect results of operations. o Other Effects. A strong housing construction market in Chicago has contributed to residential and small commercial and industrial customer volume growth, partially offset by the unfavorable impact of a slower economy on large commercial and industrial customers. o Rate Changes. The decrease in revenues attributable to rate changes reflects a 5% residential rate reduction, effective October 1, 2001, required by the Illinois restructuring legislation. The reduction in Wholesale and Miscellaneous revenues in 2001 as compared to 2000, as if the restructuring occurred on January 1, 2000, reflects a $101 million reduction in off-system sales due to the expiration of wholesale contracts that were offered by ComEd from June 2000 to May 2001 to support the open access program in Illinois, partially offset by a $58 million increase in transmission service revenue and the reversal of a $15 million reserve for revenue refunds to ComEd's municipal customers as a result of a favorable FERC ruling. FUEL AND PURCHASED POWER EXPENSE Fuel and purchased power expense increased $16 million, or 1%, compared to 2000, excluding the effects of restructuring. The increase in fuel and purchased power expense was 51 primarily attributable to increases in the weighted average on-peak/off-peak cost per MWh, offset in part by a decrease in MWhs purchased. OPERATING AND MAINTENANCE EXPENSE Operating and maintenance (O&M) expense decreased $23 million, or 2%, compared to 2000, excluding the effects of restructuring. The decrease in O&M expense was primarily attributable to a decrease in customer credit and billing costs due to process improvements and a decrease in storm restoration and service reliability costs, partially offset by higher administrative and general costs. MERGER-RELATED COSTS Merger-related costs charged to expense in 2000 were $67 million consisting of $26 million of direct incremental costs and $41 million for employee costs. Direct incremental costs represent expenses directly associated with completing the Merger, including professional fees, regulatory approval, and other merger integration costs. Employee costs represent estimated severance payments provided for under Exelon's Merger Separation Plan (MSP) for eligible employees whose positions were eliminated before October 20, 2000 due to integration activities of the merged companies. DEPRECIATION AND AMORTIZATION EXPENSE Depreciation and amortization expense decreased $51 million, or 7%, compared to 2000, excluding the effects of restructuring. Regulatory asset and decommissioning amortization decreased $180 million primarily due to the gain on the settlement of the common stock forward purchase arrangement in the first quarter of 2000, partially offset by a $103 million increase in goodwill amortization representing the impact of a full year of amortization expense in 2001 and a $26 million increase in depreciation expense from increased plant in service due to continued transmission and distribution capital improvements. Consistent with the provisions of the Illinois legislation, regulatory assets may be recovered at amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold. See ITEM 8. Financial Statements - ComEd -Note 5- Regulatory Issues. Annual goodwill amortization of $126 million in 2001 was discontinued in 2002 upon the adoption of SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142). TAXES OTHER THAN INCOME Taxes other than income decreased $81 million, or 21%, compared to 2000, excluding the effects of restructuring. The decrease in taxes other than income was primarily attributable to the effect of the change in certain revenue taxes from operating revenue and tax expense to collections recorded as liabilities resulting from Illinois legislation. INTEREST CHARGES Interest charges consist of interest expense and distributions on Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts. Interest charges increased $12 million, or 2%, compared to 2000, excluding the effects of restructuring. The increase in interest expense was primarily attributable to increased interest accrued on estimated tax liabilities and interest due on amounts payable to affiliates. OTHER INCOME AND DEDUCTIONS Other income and deductions, excluding interest charges, decreased $194 million, compared to 2000. The decrease was primarily attributable to the $113 million gain on the forward share purchase arrangement recognized during 2000 and a $115 million reduction in intercompany interest income in 2001 from an affiliate, Unicom Investment, Inc., reflecting the impact of declining interest rates and a $850 million reduction in intercompany notes receivable 52 in the fourth quarter of 2000, partially offset by the $38 million loss on the sale of Cotter Corporation, a ComEd subsidiary, recognized during 2000. INCOME TAXES The effective income tax rate was 45.5% in 2001, compared to 31.1% in 2000. The increase in the effective tax rate was primarily attributable to the effects of the gain on the forward share purchase arrangement recorded in 2000, which was not recognized for tax purposes, a full year of goodwill amortization in 2001, which is not deductible for tax purposes, the amortization of certain recoverable transition costs, which is not deductible for tax purposes and lower investment tax credit amortization resulting from the application of purchase accounting in connection with the Merger. EXTRAORDINARY ITEMS Extraordinary charges aggregating $6 million ($4 million, net of income taxes) were incurred in 2000, and consisted of prepayment premiums and the write-off of unamortized deferred financing costs associated with the early retirement of debt. YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999 SUMMARY FINANCIAL INFORMATION - COMED

(in millions) 2000 1999 Variance ------------- ------ ----- -------- Operating Revenues $ 7,012 $ 6,793 219 Fuel and Purchased Power 1,977 1,549 428 Operating and Maintenance 2,076 2,352 (276) Merger Related Costs 67 -- 67 Depreciation and Amortization 998 836 162 Taxes Other Than Income 508 507 1 ------- ------- ------- Total Operating Expenses 5,626 5,244 382 ------- ------- ------- Operating Income 1,386 1,549 (163) ------- ------- ------- Interest Expense (596) (602) 6 Distributions on Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely the Company's Subordinated Debt Securities (30) (30) -- Other, Net 308 60 248 ------- ------- ------- Income Before Income Taxes and Extraordinary Items 1,068 977 91 Income Taxes 332 326 6 ------- ------- ------- Net Income Before Extraordinary Items 736 651 85 Extraordinary Items (net of income taxes) (4) (28) 24 ------- ------- ------- Net Income 732 623 109 Preferred and Preference Stock Dividends (3) (24) 21 ------- ------- ------- Net Income on Common Stock $ 729 $ 599 $ 130 ======= ======= =======

53 NET INCOME Net income increased $109 million or 18% in 2000 as compared to 1999. Net income was impacted by a $163 million decrease in operating income, offset by a $248 million increase in other income and deductions primarily attributable to a gain on the forward share purchase arrangement recognized during 2000 and an increase in intercompany interest income in 2000 as compared to 1999. OPERATING REVENUES Operating revenues increased $219 million, or 3% from 1999. Revenues from retail customers decreased $266 million primarily due to unfavorable weather conditions reflecting a 17% reduction in cooling degree days compared to the prior year as well as the migration of non-residential customers to ARES or PPO. Sales for resale increased $467 million primarily due to the favorable response to wholesale power purchase contracts offered by ComEd from June 2000 to May 2001 to support the open access program in Illinois as well as increased sales to other utilities as a result of the increased availability of nuclear generation. Revenues from retail customers reflect a 3% increase in MWh sales for 2000 as compared to 1999. Residential MWh deliveries increased 1%, while non-residential deliveries increased 4%. As of December 31, 2000, approximately 9,500 retail customers had elected to purchase energy from an ARES or the PPO, compared to approximately 4,700 customers as of December 31, 1999. Delivered MWh sales to such customers of 14.2 million represents 17% of total annual retail deliveries in 2000. FUEL AND PURCHASED POWER EXPENSE Fuel and purchased power expense increased $428 million, or 28% from 1999. The increase in fuel and purchased power expense was primarily attributable to the effects of the PPAs that ComEd entered into upon the sale of its fleet of fossil stations in December 1999, which resulted in increased purchased power costs, but lower fuel, O&M, and depreciation costs. OPERATING AND MAINTENANCE EXPENSE O&M expense decreased $276 million, or 12% from 1999. The decrease in O&M expense was primarily attributable to a reduction in expenses as a result of the sale of the fossil generation stations in December 1999 as well as shorter refueling outages and fewer forced outages at nuclear generation stations. The decrease also reflects costs incurred in 1999 to address billing and collection problems encountered following the implementation of a new customer information and billing system in July 1998 and lower administrative and general costs. These decreases in O&M expenses were partially offset by increased expenses associated with ComEd's increased efforts to improve the reliability of its transmission and distribution system. MERGER-RELATED COSTS Merger-related costs charged to expense in 2000 were $67 million consisting of $26 million of direct incremental costs and $41 million for employee costs. Direct incremental costs represent expenses directly associated with completing the Merger, including professional fee, regulatory approval, and other Merger integration costs. Employee costs represent estimated severance payments provided under Exelon's MSP for eligible employees whose positions were eliminated before October 20, 2000 due to integration activities of the merged companies. DEPRECIATION AND AMORTIZATION EXPENSE Depreciation and amortization expense increased $162 million, or 19% from 1999. The increase was primarily attributable to a $220 million increase in regulatory asset amortization as provided by the Illinois legislation, including the settlement of the forward share purchase 54 arrangement in 2000. The increase also reflects goodwill amortization of $23 million associated with the Merger, partially offset by an $81 million decrease in depreciation expense reflecting the fossil station sale and the fair value adjustment of ComEd's nuclear stations associated with the application of purchase accounting upon completion of the Merger. TAXES OTHER THAN INCOME Taxes other than income for 2000 were consistent with 1999. INTEREST CHARGES Interest charges remained consistent from year to year. OTHER INCOME AND DEDUCTIONS Other income and deductions, excluding interest charges, increased $248 million from 1999. The increase was primarily attributable to a $168 million increase in interest income on ComEd's notes receivables from an affiliate, Unicom Investment Inc., related to the December 1999 sale of the fossil stations. The increase also reflects the effects of a $113 million gain on the forward share purchase arrangement that occurred in 2000, compared to the $44 million loss recorded in 1999 on the same arrangement, partially offset by the $38 million loss on the sale of Cotter Corporation, a ComEd subsidiary, recognized during 2000. INCOME TAXES The effective income tax rate was 31.1% in 2000 compared to 33.4% in 1999. The decrease in the effective tax rate was primarily attributable to the effects of the gain on the forward share purchase arrangement, compared to the loss that was recognized in 1999 on the same arrangement, neither of which were recognized for tax purposes. The decrease was partially offset by the investment tax credit amortization recorded in 1999 related to the fossil station sale. EXTRAORDINARY ITEM ComEd incurred extraordinary charges aggregating $6 million ($4 million, net of tax) and $46 million ($28 million, net of tax) in 2000 and 1999, respectively, consisting of prepayment premiums and the write-off of unamortized deferred financing costs associated with the early retirement of debt. LIQUIDITY AND CAPITAL RESOURCES ComEd's capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing including the issuance of commercial paper. ComEd's access to external financing at reasonable terms is dependent on its credit ratings and the general business condition of ComEd and the industry. ComEd's business is capital intensive. Capital resources are used primarily to fund ComEd's capital requirements, including construction, repayments of maturing debt, and the payment of common stock dividends to Exelon. CASH FLOWS FROM OPERATING ACTIVITIES Cash flows provided by operations were $1.4 billion in 2001. ComEd's cash flow from operating activities primarily results from sales of electricity to a stable and diverse base of retail customers at fixed prices. ComEd's future cash flows will depend upon the ability to achieve cost savings in operations, and the impact of the economy, weather, and customer choice on its revenues. Although the amounts may vary from period to period as a result of uncertainties 55 inherent in the business, ComEd expects to continue to provide a reliable and steady source of internal cash flow from operations for the foreseeable future. CASH FLOWS FROM INVESTING ACTIVITIES Cash flows used in investing activities were $441 million in 2001. ComEd's $400 million note receivable from PECO was repaid in the second quarter of 2001. ComEd's capital expenditures were $839 million in 2001 and are expected to be approximately $781 million in 2002. Approximately two-thirds of the budgeted 2002 expenditures are for additions or upgrades to existing facilities, including reliability improvements. The remaining one third is for capital additions to support customer and load growth. ComEd anticipates that it will obtain financing, when necessary, through borrowings, the issuance of preferred securities, or capital contributions from Exelon. ComEd's proposed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors. CASH FLOWS FROM FINANCING ACTIVITIES Cash flows used in financing activities were $1.0 billion in 2001 primarily attributable to debt service and payments of dividends to Exelon. ComEd's debt financing activities in 2001 reflected the retirement of $340 million of transitional trust notes and the early retirement of $196 million in First Mortgage Bonds with available cash. ComEd expects that its common stock dividend payments to Exelon will approximate 60% of its net income in 2002. CREDIT ISSUES ComEd meets its short-term liquidity requirements primarily through the issuance of commercial paper, borrowings under bank credit facilities and borrowings from the Exelon intercompany money pool. ComEd, along with Exelon, PECO, and Generation are parties to a $1.5 billion unsecured 364-day revolving credit facility on December 12, 2001 with a group of banks. ComEd has a $300 million sublimit under the credit facility and uses the credit facility principally to support its $300 million commercial paper program. The credit facility requires ComEd to maintain a debt to total capitalization ratio of 65% or less (excluding transitional trust notes). At December 31, 2001, ComEd's debt to total capitalization ratio on that basis was 45%. At December 31, 2001, ComEd had no short-term borrowings. ComEd's access to the capital markets, including the commercial paper market, and its financing costs in those markets are dependent on its securities ratings. None of ComEd's borrowings are subject to default or prepayment as a result of a downgrading of securities ratings although such a downgrading could increase interest charges under certain bank credit facilities. ComEd from time to time enters into interest rate swaps and other derivatives that require the maintenance of investment grade ratings. Failure to maintain investment grade ratings would allow the counterparty to terminate the derivative and settle the transaction on a net present value basis. Under PUHCA and the Federal Power Act, ComEd can only pay dividends from retained or current earnings. However, the SEC has authorized ComEd to pay up to $500 million in dividends out of additional paid-in capital, provided after December 31, 2001 ComEd may not pay dividends out of paid-in capital if its common equity is less than 30% of its total capitalization (including transitional trust notes). At December 31, 2001, ComEd had retained earnings of $257 million. 56 Effective January 1, 2001, Exelon contributed to ComEd a $1.1 billion non-interest bearing receivable for the purpose of funding future income tax payments resulting from the collection of instrument funding charges. Exelon repaid $125 million of this outstanding receivable during the fourth quarter of 2001 and the remainder will be repaid in the years 2002 through 2008. See ITEM 8. Financial Statements - ComEd - Note 17 - Related-Party Transactions. CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS ComEd's contractual obligations as of December 31, 2001 representing cash obligations that are considered to be firm commitments are as follows:

Payment Due within -------------------------- Due After (in millions) Total 1 Year 2-3 Years 4-5 Years 5 Years ------------- ----- ------ --------- --------- --------- Long-Term Debt $6,821 $ 849 $1,276 $1,576 $3,120 Operating Leases 186 28 51 39 68 Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding the Company's Subordinated Debt Securities 350 -- -- -- 350 ------ ------ ------ ------ ------ Total Contractual Obligations $7,357 $ 877 $1,327 $1,615 $3,538 ====== ====== ====== ====== ======

See ITEM 8. Financial Statements and Supplementary Data - ComEd, Notes to Consolidated Financial Statements for additional information about: o long-term debt see Note 10 o operating leases see Note 16 o Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding the Company's Subordinated Debt Securities see Note 13 57 ComEd's commercial commitments as of December 31, 2001 representing commitments triggered by future events, including financing arrangements to secure obligations of ComEd, are as follows:

Expiration within After ------------------------------------- ------- (in millions) Total 1 Year 2-3 Years 4-5 Years 5 Years ------------- ----- ------ --------- --------- ------- Available Lines of Credit (a) $300 $300 $-- $ -- $ -- Letters of Credit (non-debt) (b) 1 1 -- -- -- Letter of Credit (Long-term Debt) (c) 92 -- 92 -- -- ---- ---- --- ---- ------ Total Commercial Commitments $393 $301 $92 $ -- $ -- ==== ==== === ==== ======

(a) Lines of Credit - ComEd, along with Exelon, PECO, and Generation, maintain a $1.5 billion 364-day credit facility to support commercial paper issuances. ComEd has a $300 million sublimit under the credit facility. At December 31, 2001, there are no borrowings against the credit facility. (b) Letters of Credit (non-debt) - ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties. (c) Letters of Credit (Long-Term Debt) - Direct-pay letters of credit issued in connection with variable-rate debt in order to provide liquidity in the event that it is not possible to remarket all of the debt as required following specific events, including changes in the basis of determining the interest rate on the debt. As part of a settlement agreement between ComEd and the City of Chicago relating to ComEd's Chicago franchise agreement, ComEd and Chicago agreed to a revised combination of ongoing work under the franchise agreement and new initiatives that total approximately $1 billion in defined transmission and distribution expenditures by ComEd to improve electric service in Chicago, of which approximately $940 million has been expended through December 31, 2001. OTHER FACTORS ComEd participates in defined benefit pension plans and postretirement welfare sponsored by Exelon. Essentially all ComEd employees are eligible to participate in these plans. In 2001, ComEd's former plans were consolidated into the Exelon plans. Essentially all ComEd management employees, and electing union employees, hired on or after January 1, 2001 are eligible to participate in the newly established Exelon cash balance pension plan. Management employees who were active participants in the former ComEd pension plans on December 31, 2000 and remain employed by ComEd on January 1, 2002, will have the opportunity to continue to participate in the pension plan or to transfer to the cash balance plan. Participants in the cash balance plan, unlike participants in the other defined benefit plans, may request a lump-sum cash payment upon employee termination which may result in increased cash requirements from pension plan assets. ComEd may be required to increase future funding to the pension plan as a result of these increased cash requirements. Due to the performance of the United States debt and equity markets in 2001, the value of assets held in trusts to satisfy the obligations of pension and postretirement benefit plans has decreased. Also, as a result of the Merger and corporate restructuring, there was a larger than average number of employees taking advantage of retirement benefits in 2001. These factors may also result in additional future funding requirements of the pension and postretirement benefit plans. CRITICAL ACCOUNTING POLICIES The preparation of financial statements in conformity with generally accepted accounting principles requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. The following areas represent those that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain: REGULATORY ASSETS AND LIABILITIES Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities represent previous collections from customers to fund costs that have not yet been incurred. 58 ComEd is currently subject to rate freezes that limit the opportunity to recover increased expenses and the costs of new investment in facilities through rates during the rate freeze period. Current rates include the recovery of ComEd's existing regulatory assets. ComEd continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, recent rate orders to other regulated entities in the same jurisdiction, and the status of any pending or potential deregulation legislation. If future recovery of costs ceases to be probable, the assets would be required to be recognized in current period earnings. UNBILLED ENERGY REVENUES Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on daily generation volumes, estimated customer usage by class, line losses and applicable customer rates based on regression analyses reflecting significant historical trends and experience. Customer accounts receivable as of December 31, 2001 include unbilled energy revenues of $261 million on a base of annual revenue of $6.2 billion. ACCOUNTING FOR DERIVATIVE INSTRUMENTS ComEd utilizes derivatives to effectively convert fixed rate debt to floating rate debt, manage its exposure to fluctuation in interest rates related to planned future debt issuances as well as exposure to changes in the fair value of outstanding debt that is planned for early retirement. Derivative financial instruments are accounted for under SFAS No. 133. Hedge accounting has been used for all interest rate derivatives to date based on the probability of the transaction and the expected highly effective nature of the hedging relationship between the interest rate swap contract and the interest payment or changes in fair value of the hedged debt. Dealer quotes are available for all of ComEd's interest rate swap agreement derivatives. Accounting for derivatives continues to evolve through guidance issued by the Derivatives Implementation Group (DIG) of the FASB. To the extent that changes by the DIG modify current guidance, including the normal purchases and normal sales determination, the accounting treatment for derivatives may change. ENVIRONMENTAL COSTS As of December 31, 2001 ComEd had accrued liabilities of $105 million for environmental investigation and remediation costs. The liabilities are based upon estimates with respect to the number of sites for which ComEd will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties and the timing of the remediation work. Where timing and amounts of expenditures can be reliably estimated, amounts are discounted. Where timing and amounts cannot be reliably estimated, a range is estimated and the low end of the range is recognized on an undiscounted basis. Estimates can be affected by factors including future changes in technology, changes in regulations or requirements of local governmental authorities and actual costs of disposal. 59 OUTLOOK GENERAL ComEd's primary objectives are to deliver reliable service, to improve customer service and to sustain productive regulatory relationships. Achieving these goals is expected to maximize the value of ComEd's energy delivery assets. Under restructuring regulations adopted at the Federal and state levels, the role of electric utilities in the supply and delivery of energy is changing. ComEd continues to be obligated to provide reliable delivery systems under cost-based rates. It remains obligated, as a POLR, to supply generation service during the transition period to a competitive supply marketplace to customers who do not or cannot choose an alternate supplier. Retail competition for generation services has resulted in reduced revenues from regulated rates and the sale of increasing amounts of energy at market-based rates under the PPO. ComEd's revenues are affected by rate reductions and rate freezes currently in effect. The rate freeze limits ComEd's ability to recover increased expenses and the costs of investments in new transmission and distribution facilities through rates. As a result, ComEd's future results of operations will be dependent on its ability: o to deliver electricity to its customers cost-effectively, particularly in light of the current capital expenditure requirements and caps on rates, o to realize cost savings and synergies from the Merger to offset increased costs on new investments and inflation while its delivery rates are capped and, o to manage its provider of last resort responsibilities. ComEd's results of operations will be affected by a legislatively mandated 5% residential base rate reduction that became effective in October 2001, a base rate freeze that will remain generally effective until at least January 1, 2005 and the collection of transition charges through 2006. ComEd's obligations to make capital expenditures, combined with the rate freeze, could affect its earnings during the rate freeze period. ComEd is obligated to make capital expenditures with respect to its transmission and distribution system, including defined projects within the City of Chicago (City) as a result of a settlement agreement with the City totaling approximately $1 billion and at least $2 billion during the period 1999 through 2004 on transmission and distribution facilities outside of the City as a result of Illinois legislation. Given ComEd's commitments to improve the reliability of its transmission and distribution system, ComEd expects that its capital expenditures will exceed depreciation on its rate base assets through at least 2002. The base rate freeze will generally preclude rate recovery of and on those investments prior to January 1, 2005. Unless ComEd can offset the additional carrying costs against cost savings, its return on investment may be reduced during the period of the rate freeze and until rate increases are approved authorizing a return of and on this new investment. All of ComEd's non-residential customers have the right to choose their electricity suppliers, and all of its residential customers will have this right as of May 1, 2002. At December 31, 2001, approximately 21% of ComEd's small commercial and industrial load, 52% of its large commercial and industrial load, and 15% of its public authority & electric railroad load were purchasing their electric energy from an ARES or the PPO. ComEd has entered into long-term agreements with Generation to procure its power 60 needs and achieve some certainty during the next several years with respect to its POLR obligations. ComEd's agreement allows it to obtain sufficient power to meet its power needs at fixed rates. In Illinois, utilities are required to offer bundled rates frozen at levels established prior to restructuring legislation until January 2005. The POLR issue requires resolution in the near term, as the answer will affect pricing, competitive market development and planning by utilities, alternate suppliers and customers. ComEd has made an informal proposal, regarding its future provider of last resort obligations. The proposal seeks to balance the desire for a reliable supply of electricity at a reasonable price with more price certainty for smaller customers, such as residential customers, while continuing to develop a functioning competitive wholesale market for generation services. The proposal offers large customers a default power and energy offering at spot market rates, thereby freeing the utility from maintaining a long-term portfolio and making that capacity available to alternative suppliers. The proposal affords certainty of supply for large customers, but not price certainty. Recognizing that small customers may not yet have the same competitive options as large customers, the proposal offers small customers both supply and price certainty, protecting those customers from market volatility. The proposal would require regulatory action in order to become effective, and no assurance can be provided as to the timing of such action or the ultimate result of such action. Transmission. ComEd provides wholesale and unbundled retail transmission service under rates established by FERC. FERC has used its regulation of transmission to encourage competition for wholesale generation services and the development of regional structures to facilitate regional wholesale markets. In December 1999, FERC issued Order No. 2000 requiring jurisdictional utilities to file a proposal to form an RTO or, alternatively, to describe efforts to participate in or work toward participating in an RTO or explain why they were not participating in an RTO. Order 2000 is generally designed to separate the governance and operation of the transmission system from generation companies and other market participants. In response to Order 2000, ComEd and several other utilities filed a business plan in August 2001 with FERC describing the creation of Alliance Transco as an independent, for-profit transmission company. In connection with the process leading to the FERC filing, ComEd issued a non-binding declaration of intent to divest to Alliance Transco transmission facilities having a gross book value in excess of $1 billion. In a related action, ComEd entered into a non-binding memorandum of understanding with National Grid, the proposed manager of Alliance Transco, setting forth general principles relating to the divestiture and Alliance Transco as a basis for further discussion. On December 20, 2001, FERC issued several orders relating to RTOs operating in the Midwest. In those orders, FERC, among other things, approved MISO as an RTO and found that Alliance Transco lacked sufficient scope to be a stand-alone RTO. FERC also directed the Alliance participants to explore with the MISO how the participants' business plan can be accommodated with the MISO operational framework and dismissed the business plan filed in August 2001 by the Alliance participants. In addition, FERC determined that National Grid is not a market participant within the meaning of Order 2000 and, thus, is eligible to become the managing member of Alliance Transco if that entity is formed. FERC further directed the Alliance participants to file a statement of their plans to join an RTO, including timeframes, within 60 days. As a result of the FERC orders, representatives of ComEd and the other Alliance participants are exploring various RTO participation options and are meeting with representatives of MISO to explore how the Alliance Transco may operate under the MISO. The Alliance participants, including ComEd, filed their discussions with MISO at the FERC in February 2002, 61 noting progress as to some issues, but also noted negotiations were ongoing. The Alliance participants also noted that they were exploring the possibility of filing their business plan within an RTO other than MISO. Following further discussions, the Alliance participants and the National Grid concluded that further negotiations with the MISO required policy resolutions from FERC. Accordingly, on March 6, 2002, the Alliance participants and National Grid submitted a petition to FERC for a declaratory order finding that the proposed policy resolutions contained in the petition provide an appropriate basis for the participation of the Alliance participants in the MISO. The filing requests FERC to approve a proposed division of responsibilities between National Grid and the MISO. It also seeks approval to use existing systems for startup of operations in order to speed up initial operations. It requests approval for the Alliance participants to purchase services from the MISO at incremental costs, and that the MISO refund the $60 million withdrawal fee, plus interest, to ComEd, Illinois Power, and Ameren, of which ComEd's portion is $36 million. The $36 million was paid to the MISO by ComEd in May 2001 under a FERC approved settlement agreement allowing ComEd, Illinois Power, and Ameren to withdraw from the MISO to join the Alliance Transco. OTHER FACTORS Inflation affects ComEd through increased operating costs and increased capital costs for electric plant. As a result of the rate freeze imposed under the legislation in Illinois and price pressures due to competition, ComEd may not be able to pass the costs of inflation through to customers. ComEd participates in defined benefit pension plans and postretirement welfare sponsored by Exelon. Essentially all ComEd employees are eligible to participate in these plans. In 2001, ComEd's former plans were consolidated into the Exelon plans. Exelon adopted an amendment to the former ComEd postretirement medical benefit plan that changed the eligibility requirement of the plan to cover employees taking their pensions with ten years of service after age 45 rather than ten years of service and having attained the age of 55. ComEd's costs of providing pension and postretirement benefits to its retirees is dependent upon a number of factors, such as the discount rate, rates of return on plan assets, and the assumed rate of increase in health care costs. Although ComEd's pension and postretirement expense is determined using three-year averaging and is not as vulnerable to a single year's change in rates, these costs are expected to increase in 2002 and beyond as the result of the above noted plan changes along with the affects of the decline in market value of plan assets, changes in appropriate assumed rates of return on plan assets and discount rates, and increases in health care costs. For a discussion of ComEd's pension and postretirement benefit plans, see ITEM 8. Financial Statements - ComEd -Note 12- Retirement Benefits. Environmental. ComEd's operations have in the past and may in the future require substantial capital expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, ComEd is generally liable for the costs of remediating environmental contamination of property now or formerly owned by ComEd and of property contaminated by hazardous substances generated by ComEd. ComEd owns or leases a number of real estate parcels, including parcels on which its operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. ComEd has identified 44 sites where former manufactured gas plant (MGP) activities have or may have resulted in actual site contamination. ComEd is currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject 62 to additional proceedings in the future. As of December 31, 2001 and 2000, ComEd had accrued $105 million and $117 million, respectively, for environmental investigation and remediation costs, including $100 million and $110 million, respectively, (reflecting discount rates of 5.5%) for MGP investigation and remediation that currently can be reasonably estimated. ComEd expects to expend $28 million for environmental remediation activities in 2002. ComEd cannot predict whether it will incur other significant liabilities for any additional investigation and remediation costs at these or additional sites identified by ComEd, environmental agencies or others, or whether such costs will be recoverable from third parties. Security Issues and Other Impacts of Terrorist Actions. The events of September 11, 2001 have affected ComEd's operating procedures and costs and are expected to affect the cost and availability of the insurance coverages that ComEd carries. ComEd has initiated security measures to safeguard its employees and critical operations and is actively participating in industry initiatives to identify methods to maintain the reliability of its delivery systems. It is expected that governmental authorities will be working to ensure that emergency plans are in place and that critical infrastructure vulnerabilities are addressed. The electric utility industry is proposing security guidelines rather than government mandated standards to protect critical infrastructures. It is not known if Federal standards will be issued to the electric or gas industries. ComEd is evaluating enhanced security measures at certain critical locations, enhanced response and recovery plans and assessing longer term design changes and redundancy measures. These measures will involve additional expense to develop and implement. ComEd carries property damage and liability insurance for its properties and operations. As a result of significant changes in the insurance marketplace, due in part to the September 11, 2001 terrorist acts, the available coverage and limits may be less than the amount of insurance obtained in the past, and the recovery for losses due to terrorists acts may be limited. ComEd is self-insured to the extent that any losses may exceed the amount of insurance maintained. Damage to ComEd's properties could disrupt the transmission or distribution of electricity and significantly and adversely affect results of operations. ComEd cannot predict the effects on operations of the availability of property damage and liability coverage or any disruptions to its delivery facilities. NEW ACCOUNTING PRONOUNCEMENTS In 2001, the FASB issued SFAS No. 141, "Business Combinations" (SFAS No. 141), SFAS No. 142, SFAS No. 143, "Asset Retirement Obligations" (SFAS No. 143), and SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). SFAS No. 141 requires that all business combinations be accounted for under the purchase method of accounting and establishes criteria for the separate recognition of intangible assets acquired in business combinations. SFAS No. 141 is effective for business combinations initiated after June 30, 2001. SFAS No. 142 establishes new accounting and reporting standards for goodwill and intangible assets. ComEd adopted SFAS No. 142 as of January 1, 2002. Under SFAS No. 142, effective January 1, 2002, goodwill recorded by ComEd is no longer subject to amortization. After January 1, 2002, goodwill will be subject to an assessment for impairment using a two-step fair value based test, the first step of which must be performed at least annually, or more 63 frequently if events or circumstances indicate that goodwill might be impaired. The first step compares the fair value of a reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step compares the carrying amount of the goodwill to the fair value of the goodwill. If the fair value of goodwill is less than the carrying amount, an impairment loss would be reported as a reduction to goodwill and a charge to operating expense, except at the transition date, when the loss would be reflected as a cumulative effect of a change in accounting principle. As of December 31, 2001, ComEd's Consolidated Balance Sheets reflected approximately $4.9 billion in Goodwill net of accumulated amortization. Annual amortization of goodwill of $126 million was discontinued upon adoption of SFAS No. 142. In the first quarter of 2002, ComEd completed the first step of the transitional impairment analysis which indicated that its goodwill is not impaired. SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. This statement is effective for fiscal years beginning after June 15, 2002 with initial application as of the beginning of the fiscal year. ComEd is in the process of evaluating the impact of SFAS No. 143 on its financial statements. SFAS No. 144 establishes accounting and reporting standards for both the impairment and disposal of long-lived assets. This statement is effective for fiscal years beginning after December 15, 2001 and provisions of this statement are generally applied prospectively. ComEd is in the process of evaluating the impact of SFAS No. 144 on its financial statements and does not expect the impact to be material. PECO GENERAL On October 20, 2000, PECO became a wholly owned subsidiary of Exelon as a result of the transactions relating to the Merger. During January 2001, Exelon undertook a restructuring to separate its generation and other competitive businesses from its regulated energy delivery business. As part of the restructuring, the non-regulated operations and related assets and liabilities of PECO, representing the generation and enterprises business segments, were transferred to separate subsidiaries of Exelon. As a result, beginning January 2001, the operations of PECO consist of its retail electricity distribution and transmission business in southeastern Pennsylvania and its natural gas distribution business located in the Pennsylvania counties surrounding the City of Philadelphia. The estimated impact of the restructuring set forth herein reflects the effects of removing the generation and enterprises operations and obtaining energy and capacity from Generation under the terms of the PPA for the year ended December 31, 2000. 64 RESULTS OF OPERATIONS YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000 SUMMARY FINANCIAL INFORMATION - PECO

Components of Variance ---------------------------- Restructuring Normal (in millions) 2001 2000 Impact Operations Total ------------- -------- ------- ---------- ---------- -------- Operating Revenues $ 3,965 $ 5,950 $(2,577) $ 592 $(1,985) Fuel and Purchased Power 1,802 2,127 (793) 468 (325) Operating and Maintenance 587 1,791 (1,299) 95 (1,204) Merger-Related Costs -- 248 (181) (67) (248) Depreciation and Amortization 416 325 (142) 233 91 Taxes Other Than Income 161 237 (71) (5) (76) ------- ------- ------- ------- ------- Total Operating Expenses 2,966 4,728 (2,486) 724 (1,762) ------- ------- ------- ------- ------- Operating Income 999 1,222 (91) (132) (223) ------- ------- ------- ------- ------- Interest Expense (413) (457) 48 (4) 44 Distributions on Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership, which holds Solely Subordinated Debentures of the Company (10) (8) -- (2) (2) Equity in Earnings (Losses) of Unconsolidated Affiliates, Net -- (41) 41 -- 41 Other, Net 46 41 (19) 24 5 ------- ------- ------- ------- ------- Income Before Income Taxes, Extraordinary Item and Cumulative Effect of a Change of Accounting Principle 622 757 (21) (114) (135) Income Taxes 197 270 26 (99) (73) ------- ------- ------- ------- ------- Net Income Before Extraordinary Item and Cumulative Effect of a Change of Accounting Principle 425 487 (47) (15) (62) Extraordinary Item (net of income taxes) -- (4) -- 4 4 Cumulative Effect of a Change of Accounting Principle -- 24 (24) -- (24) ------- ------- ------- ------- ------- Net Income 425 507 (71) (11) (82) Preferred Stock Dividends (10) (10) -- -- -- ------- ------- ------- ------- ------- Net Income on Common Stock $ 415 $ 497 $ (71) $ (11) $ (82) ======= ======= ======= ======= =======

NET INCOME Net income from normal operations decreased $11 million, or 3% in 2001 as compared to 2000. PECO's results from normal operations improved as a result of lower margins due to the unplanned return of certain commercial and industrial customers, milder weather, increased depreciation and amortization expense and higher interest expense partially offset by favorable rate adjustments. 65 OPERATING REVENUES Bundled service reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy, the delivery cost of the transmission and distribution of the energy and a CTC/ITC charge. Unbundled service reflects customers electing to receive electric generation service from an alternative energy supplier. Revenue from customers receiving generation from an alternate supplier includes a transmission and distribution charge and a CTC/ITC charge. PECO's electric sales statistics are as follows:

--------------------- ---------- ------------ ------------ Deliveries - (in MWh) 2001 2000 Variance --------------------- ---------- ------------ ------------ BUNDLED DELIVERIES Residential 8,072,915 9,324,800 (1,251,885) Small Commercial & Industrial 5,997,571 3,918,529 2,079,042 Large Commercial & Industrial 12,960,295 8,291,607 4,668,688 Public Authorities & Electric Railroads 765,554 478,809 286,745 ---------- ---------- ---------- 27,796,335 22,013,745 5,782,590 ---------- ---------- ---------- UNBUNDLED DELIVERIES Residential 3,104,811 1,985,614 1,119,197 Small Commercial & Industrial 1,606,067 3,549,667 (1,943,600) Large Commercial & Industrial 2,351,520 7,404,363 (5,052,843) Public Authorities & Electric Railroads 7,285 300,978 (293,693) ----------- ---------- ---------- 7,069,683 13,240,622 (6,170,939) ----------- ---------- ---------- TOTAL RETAIL DELIVERIES 34,866,018 35,254,367 (388,349) =========== ========== ==========

------------------------------- ---------- ------------ ------------ Electric Revenues (in millions) 2001 2000 Variance ------------------------------- ---------- ------------ ------------ BUNDLED REVENUE Residential $ 1,028 $ 1,113 $ (85) Small Commercial & Industrial 682 422 260 Large Commercial & Industrial 929 532 397 Public Authorities & Electric Railroads 72 47 25 ------------ ------------ ------------ 2,711 2,114 597 ------------ ------------ ------------ UNBUNDLED REVENUE Residential 235 135 100 Small Commercial & Industrial 81 154 (73) Large Commercial & Industrial 64 180 (116) Public Authorities & Electric Railroads 1 11 (10) ------------ ------------ ------------ 381 480 (99) ------------ ------------ ------------ TOTAL ELECTRIC RETAIL REVENUES 3,092 2,594 498 Wholesale and Miscellaneous Revenue 219 247 (28) ------------ ------------ ------------ TOTAL ELECTRIC REVENUE $ 3,311 $ 2,841 $ 470 ============ ============ ============

66 The changes in electric retail revenues for 2001, as compared to 2000, are as follows:

(in millions) Variance ------------- -------- Customer Choice $ 276 Rate Changes 241 Weather (5) Other Effects (14) ----- Retail Revenue $ 498 =====

Customer Choice. All PECO customers have choice to purchase energy from other suppliers. This choice generally does not impact kWh deliveries, but reduces revenue collected from customers because they are not obtaining generation supply from PECO. Customers who are served by an alternate supplier continue to pay competitive transition charges. As of December 31, 2001, the customer load served by alternate suppliers was 1,003 MWh or 13.0% as compared to the same prior year period of 2,631 MW or 34.9%. For the year ended December 31, 2001, the percent of MWh sold by PECO increased by 17.2% to 79.8% of total retail deliveries as compared to 62.6% in 2000. This reduction in the customer load and the percentage of MWh served by alternate suppliers, primarily resulted from small and large commercial and industrial customers selecting or returning to PECO as their electric generation supplier. As of December 31, 2001, the number of customers served by alternate suppliers was 371,500 or 24.4% as compared to December 31, 2000 of 269,395 or 18.0%. The increase from the prior year is primarily a result of the Competitive Default Service (CDS) agreements for residential customers with the New Power Company and Green Mountain Energy Company. As of December 31, 2001, there were 227,349 residential customers assigned to these generation providers as part of the agreement. As of December 31, 2001, the customer load served by a alternate suppliers was 1,003 MWh or 13.0% as compared to the same prior year period of 2,631 MWh or 34.9%. Rate Changes. The increase in revenues attributable to rate changes reflects the expiration of a 6% reduction in PECO's electric rates in effect for 2000, partially offset by a $60 million rate reduction in effect for 2001. Weather. The demand for electricity and gas services is impacted by weather conditions. Very warm weather in summer months and very cold weather in other months is referred to as "favorable weather conditions", because these weather conditions result in increased demand for electricity. Conversely, mild weather reduces demand. The weather impact was unfavorable compared to the prior year as a result of warmer winter weather partially offset by warmer summer weather. Cooling degree days increased 34% in 2001 compared to 2000 while heating degree days decreased 12% in 2001 compared to 2000. Other Effects. Other items affecting revenue during 2001 include: o Volume. Exclusive of weather impacts, lower delivery volume affected PECO's revenue by $21 million compared to 2000. Total kWh sales to retail customers decreased 1% compared to 2000, primarily as a result of less favorable economic conditions in 2001 offset by customer growth. Large commercial and industrial sales decreased 2% and residential sales decreased 1%. These were partially offset by an increase in small commercial and industrial sales of 2%. o Other. The payment of $29 million to Generation related to nuclear decommissioning cost recovery under an agreement effective September 2001 partially offset by an $11 million settlement of competitive transition charges by a large customer. 67 PECO's gas sales statistics are as follows:

2001 2000 Variance ------ ------ -------- Deliveries in million cubic feet (mmcf) 81,528 91,686 (10,158) Revenue (in millions) $ 654 $ 532 $ 122 ------- ------- --------

The changes in gas revenue for 2001, as compared to 2000, are as follows:

(in millions) Variance ------------ -------- Price $ 174 Weather (38) Volume (14) ----- Gas Revenue $ 122 =====

o Price. The favorable variance in price is attributable to an adjustment of the purchased gas cost recovery by the PUC effective in December 2000. The average price per million cubic feet for all customers for 2001 was 38% higher than in 2000. PECO's gas rates are subject to periodic adjustments by the PUC designed to recover or refund the difference between actual cost of purchased gas and the amount included in base rates and to recover or refund increases or decreases in certain state taxes not recovered in base rates. o Weather. The unfavorable weather impact is attributable to warmer temperatures in the non-summer months of 2001 than in 2000 in the PECO service territory. Heating degree days decreased 12% in 2001 compared to 2000. o Volume. Exclusive of weather impacts, lower delivery volume affected revenue by $14 million compared to 2000. Total mmcf sales to retail customers decreased 11% compared to 2000, primarily as a result of slower economic conditions in 2001 offset by increased customer growth. FUEL AND PURCHASED POWER EXPENSE Fuel and purchased power expense for 2001 increased $468 million, or 35%, as compared to the same 2000 period, excluding the effects of the restructuring. The increase in fuel and purchased power expense was primarily attributable to $293 million from customers in Pennsylvania selecting or returning to PECO as their electric generation supplier, $174 million from increased prices related to gas and higher PJM ancillary charges of $31 million. These increases were partially offset by $24 million as a result of unfavorable weather conditions and $14 million attributable to lower delivery volume related to gas. OPERATING AND MAINTENANCE EXPENSE O&M expense for 2001 increased $95 million, or 19%, as compared to the same 2000 period, excluding the effects of the restructuring. The increase in O&M expense was primarily attributable to $20 million related to an increased allocation of corporate expense, $18 million related to additional employee severance costs in 2001, $17 million as a result of higher administrative and general costs for functions previously performed at Corporate, $14 million related to the deployment of the automated meters during 2001, $12 million of incremental costs related to two storms in 2001, $9 million related to additional uncollectible accounts expense and $5 million associated with the write-off of excess and obsolete inventory. MERGER-RELATED COSTS Merger-related costs charged to income in 2000 were $248 million consisting of $132 million of direct incremental costs and $116 million for employee costs. Direct incremental costs represent expenses associated with completing the Merger, including professional fees, regulatory 68 approval and settlement costs, and settlement of compensation arrangements. Employee costs represent estimated severance payments and pension and postretirement benefits provided under Exelon's MSP for 642 eligible PECO employees who are expected to be involuntarily terminated before December 2002 upon completion of integration activities for the merged companies. Merger-related costs attributable to the operations transferred to Generation, Enterprises and BSC in the corporate restructuring were $181 million. The remaining $67 million is attributable to PECO's energy delivery segment. See Item 8. Financial Statements and Supplementary Data - PECO - Note 2 to Consolidated Financial Statements. DEPRECIATION AND AMORTIZATION EXPENSE Depreciation and amortization expense for 2001 increased $233 million, or 127%, as compared to the same 2000 period, excluding the effects of the restructuring. The increase was primarily attributable to $214 million of additional amortization of PECO's CTC and an increase of $19 million related to depreciation expense associated with additional plant in service. The additional amortization of the CTC is in accordance with PECO's original settlement under the Pennsylvania Competition Act. TAXES OTHER THAN INCOME Taxes other than income for 2001 decreased $5 million, or 3%, as compared to the same 2000 period, excluding the effects of the restructuring. The decrease was primarily attributable to the elimination of the gross receipts tax on gas sales effective July 1, 2000. INTEREST CHARGES Interest charges consist of interest expense and distributions on Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS). Interest charges increased $6 million, or 1% in 2001. The increase was primarily attributable to additional interest on the Transition Bonds issued to securitize PECO's stranded cost recovery of $16 million and interest expense related to a loan from an affiliate in 2001 of $8 million, partially offset by the reduction of PECO's long-term debt with the proceeds from Transition Bonds, which reduced interest charges by $18 million. EQUITY IN EARNINGS (LOSSES) OF UNCONSOLIDATED AFFILIATES As part of the corporate restructuring, PECO's unconsolidated affiliates were transferred to Generation and Enterprises. OTHER INCOME AND DEDUCTIONS Other income and deductions excluding interest charges and equity in earnings (losses) of unconsolidated affiliates increased $24 million, or 109% in 2001 as compared to 2000, excluding the effects of the restructuring. The increase in other income and deductions was primarily attributable to intercompany interest income of $10 million in the third quarter of 2001, a gain on the settlement of an interest rate swap of $6 million and the favorable settlement of a customer contract of $3 million. INCOME TAXES The effective tax rate was 31.7% in 2001 as compared to 35.7% in 2000. The decrease in the effective tax rate was primarily attributable to tax benefits associated with the implementation of State tax planning Strategies, a favorable adjustment to prior period income taxes in connection with the completion of the 2000 tax return and the reduced impact of investment tax credit amortization. 69 EXTRAORDINARY ITEMS In 2000, PECO incurred extraordinary charges aggregating $6 million ($4 million, net of tax) related to prepayment premiums and the write-off of unamortized deferred financing costs associated with the early retirement of debt with a portion of the proceeds from the securitization of PECO's stranded cost recovery in May 2000. CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE In 2000, PECO recorded a benefit of $40 million ($24 million, net of tax) representing the cumulative effect of a change in accounting method for nuclear outage costs in conjunction with the synchronization of accounting policies in connection with the Merger. PREFERRED STOCK DIVIDENDS Preferred stock dividends for 2001 were consistent as compared to 2000. 70 YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999 SUMMARY FINANCIAL INFORMATION - PECO

(in millions) 2000 1999 Variance ------------- ------- ------- -------- Operating Revenues $5,950 $5,478 $ 472 Fuel and Purchased Power 2,127 2,152 (25) Operating and Maintenance 1,791 1,454 337 Merger-Related Costs 248 -- 248 Depreciation and Amortization 325 237 88 Taxes Other Than Income 237 262 (25) ------ ------ ----- Total Operating Expenses 4,728 4,105 623 ------ ------ ----- Operating Income 1,222 1,373 (151) ------ ------ ----- Interest Expense (457) (396) (61) Distributions on Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership, which holds Solely Subordinated Debentures of the Company (8) (21) 13 Equity in Earnings (Losses) of Unconsolidated Affiliates, Net (41) (38) (3) Other, Net 41 59 (18) ------ ------ ----- Income Before Income Taxes, Extraordinary Item and Cumulative Effect of a Change of Accounting Principle 757 977 (220) Income Taxes 270 358 (88) ------ ------ ----- Net Income Before Extraordinary Item and Cumulative Effect of Changes of Accounting Principles 487 619 (132) Extraordinary Item (net of income taxes) (4) (37) 33 Cumulative Effect of Changes of Accounting Principles 24 -- 24 ------ ------ ----- Net Income 507 582 (75) Preferred Stock Dividends (10) (12) 2 ------ ------ ----- Net Income on Common Stock $ 497 $ 570 $ (73) ====== ====== =====

NET INCOME Net income decreased $75 million, or 13% in 2000, as compared to 1999 reflecting merger related expenses and amortization of CTCs in 2000. 71 OPERATING REVENUES

(in millions, except percentage data) 2000 1999 $ Variance % Variance ------------------------------------- ------ ------ ---------- --------- Energy Delivery $3,373 $3,265 $ 108 3.3% Generation 1,931 2,097 (166) (7.9)% Enterprises 646 116 530 456.9% ------ ------ ----- $5,950 $5,478 $ 472 8.6% ====== ====== ====== ---------

Energy Delivery. The increase in operating revenue from energy delivery was attributable to higher electric revenue of $32 million and additional gas revenue of $76 million. The increase in electric revenue reflects $102 million from customers in Pennsylvania selecting PECO as their electric generation supplier and rate adjustments in Pennsylvania, partially offset by a decrease of $69 million as a result of lower summer volume. Regulated gas revenue reflected increases of $44 million related to higher prices, $29 million attributable to increased volume from new and existing customers and $24 million from increased winter volume. These increases were partially offset by $21 million of lower gross receipts tax collections as a result of the repeal of the gross receipts tax on gas sales in connection with gas restructuring in Pennsylvania. Generation. The decrease in operating revenue from generation was a result of lower electric revenue of $180 million partially offset by higher gas revenue of $14 million. The decrease in electric revenue was principally attributable to lower sales of competitive retail electric generation services of $132 million, of which $196 million represented decreased volume that was partially offset by $64 million from higher prices. In addition, the termination of the management agreement for Clinton resulted in lower revenues of $99 million. As a result of the acquisition by AmerGen of Clinton in December 1999, the management agreement was terminated and, accordingly, the operations have been included in Equity in Earnings (Losses) of Unconsolidated Affiliates on PECO's Consolidated Statements of Income in 2000. These decreases were partially offset by an increase of $50 million from higher wholesale revenue attributable to $199 million associated with higher prices partially offset by $149 million related to lower volume. Unregulated gas revenue increased primarily as a result of $11 million from wholesale sales of excess natural gas. Enterprises. The increase in operating revenue from enterprises was attributable to $530 million from the acquisition of thirteen infrastructure services companies during 2000 and 1999. FUEL AND PURCHASED POWER EXPENSE

(in millions, except percentage data) 2000 1999 $ Variance % Variance ------------------------------------- ------ ------ ---------- --------- Energy Delivery $ 462 $ 370 $ 92 24.9% Generation 1,665 1,782 (117) (6.6)% ------ ------ ----- $ 2,127 $ 2,152 $ (25) (1.2)% ====== ====== ===== ---------

Energy Delivery. The increase in fuel and purchased power expense from energy delivery was primarily attributable to $73 million from additional volume and increased prices related to gas, $13 million as a result of favorable weather conditions and $4 million in additional PJM ancillary charges. 72 Generation. The decrease in fuel and purchased power expense from generation was primarily attributable to $262 million principally related to reduced sales of competitive retail electric generation services partially offset by an increase of $120 million in the cost to supply energy delivery customers and an increase of $5 million from wholesale operations principally related to $97 million as a result of increased prices partially offset by $92 million as a result of decreased volume. OPERATING AND MAINTENANCE EXPENSE

(in millions, except percentage data) 2000 1999 $ Variance % Variance ------------------------------------- ------- ------- ---------- ---------- Energy Delivery $ 491 $ 434 $ 57 13.1% Generation 616 721 (105) (14.6)% Enterprises 650 136 514 377.9% Corporate 34 163 (129) (79.1)% ------ ------ ------ $1,791 $1,454 $ 337 23.2% ====== ====== ====== -------

Energy Delivery. The increase in O&M expense from energy delivery was primarily attributable to the direct charging to the business segments of O&M expenses that were previously reported at PECO Corporate. Generation. The decrease in O&M expense from generation was primarily attributable to O&M expenses related to the management agreement for Clinton of $70 million in 1999 which has since been terminated, $15 million related to the abandonment of two information system implementations in 1999, $17 million related to lower administrative and general expenses related to the unregulated retail sales of electricity and $15 million related to lower joint-owner expenses. Enterprises. The O&M expense from enterprises increased $505 million from the infrastructure services business as a result of acquisitions. Corporate. PECO Corporate's decrease in O&M expense was primarily attributable to expenses of $56 million related to lower Year 2000 remediation expenditures, lower pension and postretirement benefits expense of $31 million and the direct charging to business segments of O&M expenses that were previously recorded at Corporate. MERGER-RELATED COSTS Merger-related costs charged to income in 2000 were $248 million consisting of $132 million of direct incremental costs and $116 million for employee costs. Direct incremental costs represent expenses associated with completing the Merger, including professional fees, regulatory approval and settlement costs, and settlement of compensation arrangements. Employee costs represent estimated severance payments and pension and postretirement benefits provided under Exelon's MSP for 642 eligible PECO employees who are expected to be involuntarily terminated before December 2002 upon completion of integration activities for the merged companies. DEPRECIATION AND AMORTIZATION EXPENSE Depreciation and amortization expense increased $88 million, or 37%, to $325 million in 2000. The increase was primarily attributable to $57 million of amortization of PECO's CTC which commenced in 2000 and $29 million related to depreciation and amortization expense associated with the infrastructure services business acquisitions. 73 TAXES OTHER THAN INCOME Taxes other than income decreased $25 million, or 10%, to $237 million in 2000. The decrease was primarily attributable to lower real estate taxes of $18 million relating to a change in tax laws for utility property in Pennsylvania and $11 million as a result of the elimination of the gross receipts tax on natural gas sales net of an increase in gross receipts tax on electric sales. This decrease was partially offset by a non-recurring $22 million capital stock tax credit related to a 1999 adjustment associated with the impact of PECO's 1997 restructuring charge. INTEREST CHARGES Interest charges consist of interest expense and distributions on COMRPS. Interest charges increased $48 million, or 12%, to $465 million in 2000. The increase was primarily attributable to interest on the Transition Bonds issued to securitize PECO's stranded cost recovery of $104 million, partially offset by the reduction of PECO's long-term debt with the proceeds from Transition Bonds, which reduced interest charges by $77 million. EQUITY IN EARNINGS (LOSSES) OF UNCONSOLIDATED AFFILIATES Equity in earnings (losses) of unconsolidated affiliates decreased $3 million, or 8%, to losses of $41 million in 2000 as compared to losses of $38 million in 1999. The decrease was primarily attributable to $8 million of additional losses from communications joint ventures, partially offset by $4 million of earnings from AmerGen as a result of the acquisitions of Clinton and TMI in December 1999 and Oyster Creek in September 2000. OTHER INCOME AND DEDUCTIONS Other income and deductions excluding interest charges and equity in earnings (losses) of unconsolidated affiliates decreased $18 million, or 31%, to $41 million in 2000 as compared to $59 million in 1999. The decrease in other income and deductions was primarily attributable to the writedown of a communications investment of $33 million, a $10 million gain on the disposal of assets in 1999 and a decrease in interest income of $2 million. These decreases were partially offset by a $15 million write-off in 1999 of the investment in a cogeneration facility in connection with the settlement of litigation and gains on sales of investments of $13 million. INCOME TAXES The effective tax rate was 35.7% in 2000 as compared to 36.6% in 1999. EXTRAORDINARY ITEMS In 2000, PECO incurred extraordinary charges aggregating $6 million ($4 million, net of tax) related to prepayment premiums and the write-off of unamortized deferred financing costs associated with the early retirement of debt with a portion of the proceeds from the securitization of PECO's stranded cost recovery in May 2000. In 1999, PECO incurred extraordinary charges aggregating $62 million ($37 million, net of tax) related to prepayment premiums and the write-off of unamortized debt costs associated with the repayment and refinancing of debt. 74 CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE In 2000, PECO recorded a benefit of $40 million ($24 million, net of tax) representing the cumulative effect of a change in accounting method for nuclear outage costs in conjunction with the synchronization of accounting policies in connection with the Merger. PREFERRED STOCK DIVIDENDS Preferred stock dividends decreased $2 million, or 17%, to $10 million as compared 1999. The decrease was attributable to the redemption of $37 million of Mandatorily Redeemable Preferred Stock in August 1999 with a portion of the proceeds from the issuance of Transition Bonds. In addition, PECO redeemed $19 million of Mandatorily Redeemable Preferred Stock in August 2000. LIQUIDITY AND CAPITAL RESOURCES PECO's capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing including the issuance of commercial paper. PECO's access to external financing at reasonable terms is dependent on its credit ratings and the general business condition of PECO and the industry. PECO's business is capital intensive. Capital resources are used primarily to fund PECO's capital requirements, including construction, repayments of maturing debt and preferred securities and payment of common stock dividends to Exelon. CASH FLOWS FROM OPERATING ACTIVITIES Cash flows provided by operations for 2001 were $828 million. PECO's cash flow from operating activities primarily results from sales of electricity and gas to a stable and diverse base of retail customers at fixed prices. PECO's future cash flows will depend upon the ability to achieve cost savings in operations, and the impact of the economy, weather and customer choice on its revenues. Although the amounts may vary from period to period as a result of the uncertainties inherent in its business, PECO expects that it will continue to provide a reliable and steady source of internal cash flow from operations for the foreseeable future. CASH FLOWS FROM INVESTING ACTIVITIES Cash flows used in investing activities for 2001 were $235 million, primarily for capital expenditures of $264 million. PECO's projected capital expenditures for 2002 are $279 million. Approximately one half of the budgeted 2002 expenditures are for capital additions to support customer and load growth and the remainder for additions to or upgrades of existing facilities. PECO anticipates that it will obtain financing, when necessary, through borrowings, the issuance of preferred securities, or capital contributions from Exelon. PECO's proposed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors. CASH FLOWS FROM FINANCING ACTIVITIES Cash flows used in financing activities were $579 million in 2001 primarily attributable to debt service and payments of dividends to Exelon. Debt financing activities during 2001 included the refinancing of $805 million in PECO transition bonds. In 2001, PECO paid Exelon $342 million in common stock dividends and currently expects that the 2002 dividend will be comparable to 2001. 75 CREDIT ISSUES PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper, borrowings under bank credit facilities and borrowings from the Exelon intercompany money pool. PECO, along with Exelon, ComEd and Generation, are parties to a $1.5 billion unsecured revolving credit facility with a group of banks. This credit facility is used principally by PECO to support its commercial paper program. PECO has a $300 million sublimit under this credit facility. At December 31, 2001, PECO had outstanding $101 million of notes payable consisting principally of commercial paper. For 2001, the average interest rate on notes payable was approximately 2.25%. Certain of the credit agreements to which PECO is a party requires PECO to maintain a debt to total capitalization ratio of 65% or less, excluding securitization debt and excluding the receivable from parent recorded in PECO's shareholders' equity. At December 31, 2001, the debt to total capitalization ratios on that basis for PECO was 38%. PECO's access to the capital markets, including the commercial paper market, and its financing costs in those markets are dependent on its securities ratings. None of PECO's borrowings are subject to default or prepayment as a result of a downgrading of securities ratings although such a downgrading could increase interest charges under PECO's bank credit facility. PECO from time to time enters into interest rate swap and other derivatives that require the maintenance of investment grade ratings. Failure to maintain investment grade ratings would allow the counterparty to terminate the derivative and settle the transaction on a net present value basis. Under PUHCA and the Federal Power Act, PECO can pay dividends only from retained or current earnings. At December 31, 2001, PECO had retained earnings of $270 million. CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS PECO's contractual obligations as of December 31, 2001 representing cash obligations that are considered to be firm commitments are as follows:

Payment due within Due after ----------------------------- --------- (in millions) Total 1 Year 2-3 Years 4-5 Years 5 Years ------------- ------ ------ --------- --------- ------- Long-Term Debt $5,992 $ 548 $1,008 $1,003 $3,433 Short-Term Debt 101 101 -- -- -- COMRPS and Preferred Stock with Mandatory Redemption Requirements 147 19 -- -- 128 Operating Leases 13 2 4 4 3 ------ ------ ------ ------ ------ Total Contractual Obligations $6,253 $ 670 $1,012 $1,007 $3,564 ====== ====== ====== ====== ======

See ITEM 8. Financial Statements and Supplementary Data - PECO, Notes to Consolidated Financial Statements for additional information about: o long-term debt see Note 11 o short-term debt see Note 10 o operating leases see Note 18 o COMRPS and Preferred Stock with Mandatory Redemption Requirements see Notes 15 and 14, respectively. 76 PECO's commercial commitments as of December 31, 2001 representing commitments triggered by future events, including obligations to make payment on behalf of other parties as well as financing arrangements to secure obligations of PECO, are as follows:

Expiration within After ---------------------------- ------- (in millions) Total 1 Year 2-3 Years 4-5 Years 5 Years ------------- ----- ------ --------- --------- ------- Available Lines of Credit (a) $300 $300 $-- $-- $-- Letters of Credit (non-debt) (b) 11 11 -- -- -- Letters of Credit (Long-Term Debt) (c) 17 -- 17 -- -- Insured Long-Term Debt (d) 154 -- 154 -- -- Guarantees (e) 100 -- -- -- 100 ---- ---- ---- --- ---- Total Commercial Commitments $582 $311 $171 $-- $100 ==== ==== ==== === ====

(a) Lines of Credit - PECO, along with Exelon, ComEd and Generation, maintain a $1.5 billion 364-day credit facility to support commercial paper issuances. PECO has a $300 million sublimit under the credit facility. At December 31, 2001, there are no borrowings against the credit facility. (b) Letters of Credit (non-debt) - PECO and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties. (c) Letters of Credit (Long-Term Debt) - Direct-pay letters of credit issued in connection with variable-rate debt in order to provide liquidity in the event that it is not possible to remarket all of the debt as required following specific events, including changes in the basis of determining the interest rate on the debt. (d) Insured Long-Term Debt - Borrowings that have been credit-enhanced through the purchase of insurance coverage equal to the amount of principal outstanding plus interest. (e) Guarantees - Provide support for lines of credit, performance contracts, surety bonds and leases as required by third parties. OFF BALANCE SHEET OBLIGATIONS PECO is party to an agreement with a financial institution under which it can sell or finance with limited recourse an undivided interest, adjusted daily, in up to $225 million of designated accounts receivable until November 2005. At December 31, 2001, PECO had sold a $225 million interest in accounts receivable, consisting of a $170 million interest in accounts receivable which PECO accounted for as a sale under SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - a Replacement of FASB Statement No. 125," and a $55 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable. See ITEM 8. Financial Statements and Supplementary Data - PECO, Note 14 of Notes to Consolidated Financial Statements. PECO retains the servicing responsibility for these receivables. The agreement requires PECO to maintain the $225 million interest, which, if not met, requires PECO to deposit cash in order to satisfy such requirements. At December 31, 2001 and 2000, PECO met this requirement and was not required to make any cash deposits. OTHER FACTORS PECO participates in defined benefit pension plans and postretirement welfare sponsored by Exelon. Essentially all PECO employees are eligible to participate in these plans. In 2001, PECO's former plans were consolidated into the Exelon plans. Essentially all PECO employees, hired on or after January 1, 2001 are eligible to participate in newly established Exelon cash balance pension plans. Employees who were active participants in the former PECO pension plans on December 31, 2000 and remain employed by PECO on January 1, 2002, will have the opportunity to continue to participate in the pension plan or to transfer to the cash balance plan. Participants in the cash balance plan, unlike participants in the other defined benefit plans, may request a lump-sum cash payment upon employee termination which may result in increased cash requirements from pension plan assets. PECO may be required to increase future funding to the pension plan as a result of these increased cash requirements. 77 Due to the performance of the United States debt and equity markets in 2001, the value of assets held in trusts to satisfy the obligations of pension and postretirement benefit plans has decreased. Also, as a result of the Merger and corporate restructuring, there was a larger than average number of employees taking advantage of retirement benefits in 2001. These factors may also result in additional future funding requirements of the pension and postretirement benefit plans. CRITICAL ACCOUNTING POLICIES The preparation of financial statements in conformity with generally accepted accounting principles requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. The following areas represent those that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain: REGULATORY ASSETS AND LIABILITIES Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities represent previous collections from customers to fund costs which have not yet been incurred. PECO is currently subject to a rate freeze that limits the opportunity to recover increased costs and the costs of new investment in facilities through rates during the rate freeze period. Current rates include the recovery of PECO's existing regulatory assets. PECO continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, recent rate orders to other regulated entities in the same jurisdiction, and the status of any pending or potential deregulation legislation. If future recovery of costs ceases to be probable the assets would be required to be recognized in current period earnings. UNBILLED ENERGY REVENUES Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters which are read on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on daily generation volumes, estimated customer usage by class, line losses and applicable customer rates based on regression analyses reflecting significant historical trends and experience. Customer accounts receivable as of December 31, 2001 include unbilled energy revenues of $100 million on a base of annual revenues of $4.0 billion. 78 ACCOUNTING FOR DERIVATIVE INSTRUMENTS PECO utilizes derivatives to manage its exposure to fluctuation in interest rates related to outstanding variable rate debt instruments and planned future debt issuances as well as exposure to changes in the fair value of outstanding debt that is planned for early retirement. Derivative financial instruments are accounted for under SFAS No. 133. Hedge accounting has been used for all interest rate derivatives to date based on the probability of the transaction and the expected highly effective nature of the hedging relationship between the interest rate swap contract and the interest payment or changes in fair value of the hedged debt. Dealer quotes are available for all of PECO's interest rate swap agreement derivatives. Accounting for derivatives continues to evolve through guidance issued by the DIG of the FASB. To the extent that changes by the DIG modify current guidance, including the normal purchases and normal sales determination, the accounting treatment for derivatives may change. ENVIRONMENTAL COSTS As of December 31, 2001 PECO had accrued liabilities of $37 million for environmental investigation and remediation costs. The liabilities are based upon estimates with respect to the number of sites for which PECO will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties and the timing of the remediation work. Where timing and amounts of expenditures can be reliably estimated, amounts are discounted. Where timing and amounts cannot be reliably estimated, a range is estimated and the low end of the range is recognized on an undiscounted basis. Estimates can be affected by factors including future changes in technology, changes in regulations or requirements of local governmental authorities and actual costs of disposal. OUTLOOK GENERAL PECO believes that it will provide a significant and steady source of earnings. PECO's primary goals are to deliver reliable service, to improve customer service and to sustain productive regulatory relationships. Achieving these goals is expected to maximize the value of PECO's assets. Under restructuring regulations adopted at the Federal and state levels, the role of electric utilities in the supply and delivery of energy is changing. PECO continues to be obligated to provide reliable delivery systems under cost-based rates. It remains obligated, as a provider of last resort, to supply generation service during the transition period to a competitive supply marketplace to customers who do not or cannot choose an alternate supplier. Retail competition for generation services has resulted in reduced revenues from regulated rates and the sale of increasing amounts of energy at market-based rates. PECO's revenues will be affected by rate reductions and rate freezes currently in effect. The rate freezes limit PECO's ability to recover increased expenses and the costs of investments in new transmission and distribution facilities through rates. As a result, PECO's future results of operations will be dependent on its ability: o to deliver electricity and gas to its customers cost-effectively, o to realize cost savings and synergies from the Merger to offset increased costs on new investments and inflation while its delivery rates are capped and, o to manage its provider of last resort responsibilities. 79 PECO's results will be affected by annual increases in amortization of its stranded cost recovery through 2010. PECO has been authorized to recover stranded costs of $5.3 billion ($4.9 billion of unamortized costs at December 31, 2001) over a twelve-year period ending December 31, 2010 with a return on the unamortized balance of 10.75%. In 2001, revenue attributable to stranded cost recovery was $797 million and is scheduled to increase to $932 million by 2010, the final year of stranded cost recovery. Amortization of PECO's stranded cost recovery, which is a regulatory asset, is included in depreciation and amortization. The amortization expense for 2001 was $271 million and will increase to $879 million by 2010. All of PECO's retail customers have the right to choose their electricity suppliers. At December 31, 2001, approximately 28% of PECO's residential load, 6% of its small commercial and industrial load and 5% of its large commercial and industrial load were purchasing generation service from an alternate supplier. PECO has entered into a long-term agreement with Generation to procure its power needs and achieve some certainty during the next several years with respect to these obligations. Because PECO's agreement with Generation allows it to obtain sufficient power at the rates it is allowed to charge to serve customers who do not choose alternate generation suppliers revenues and expenses may vary with customer choice, but income will not be significantly impacted. Transmission. PECO provides wholesale transmission service under rates established by FERC. FERC has used its regulation of transmission to encourage competition for wholesale generation services and the development of regional structures to facilitate regional wholesale markets. In December 1999, FERC issued Order 2000 requiring jurisdictional utilities to file a proposal to form an RTO or, alternatively, to describe efforts to participate in or work toward participating in an RTO or explain why they were not participating in an RTO. Order 2000 is generally designed to separate the governance and operation of the transmission system from generation companies and other market participants. PECO provides regional transmission service pursuant to a regional open-access transmission tariff filed by it and the other transmission owners who are members of PJM. PJM is a power pool that integrates, through central dispatch, the generation and transmission operations of its member companies across a 50,000 square mile territory. 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. PJM's Office of Interconnection is the ISO for PJM (PJM ISO) and is responsible for operation of the PJM control area and administration of the PJM open-access transmission tariff. PECO and the other transmission owners in PJM have turned over control of their transmission facilities to the PJM ISO. The PJM ISO and the transmission owners who are members of PJM, including PECO, have filed with FERC for approval of PJM as an RTO. FERC has conditionally approved the PJM RTO. OTHER FACTORS Inflation affects PECO through increased operating costs and increased capital costs for electric plant. As a result of the rate caps imposed under the legislation in Pennsylvania and price pressures due to competition, PECO may not be able to pass the costs of inflation through to customers. PECO participates in defined benefit pension plans and postretirement welfare sponsored by Exelon. Essentially all PECO employees are eligible to participate in these plans. In 2001, PECO's former plans were consolidated into the Exelon plans. PECO's costs of providing pension and postretirement benefits to its retirees is dependent upon a number of factors, such as 80 the discount rate, rates of return on plan assets, and the assumed rate of increase in health care costs. Although PECO's pension and postretirement expense is determined using three-year averaging and is not as vulnerable to a single year's change in rates, these costs are expected to increase in 2002 and beyond as the result of the above noted plan changes along with the affects of the decline in market value of plan assets, changes in appropriate assumed rates of return on plan assets and discount rates, and increases in health care costs. For a discussion of PECO's pension and postretirement benefit plans, see Item 8. Financial Statements and Supplementary Data - PECO - Note 13 of the Notes to Consolidated Financial Statements. Environmental. PECO's operations have in the past and may in the future require substantial capital expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, PECO is generally liable for the costs of remediating environmental contamination of property now or formerly owned by PECO and of property contaminated by hazardous substances generated by PECO. PECO owns or leases a number of real estate parcels, including parcels on which its operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. PECO has identified 28 sites where former MGP activities have or may have resulted in actual site contamination. PECO is currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. As of December 31, 2001 and 2000, PECO had accrued $37 million and $54 million, respectively, for environmental investigation and remediation costs, including $27 million and $30 million, respectively, for MGP investigation and remediation that currently can be reasonably estimated. In conjunction with the corporate restructuring in January 2001, a portion of the environmental investigation and remediation costs were transferred to Generation. PECO expects to expend $2 million for environmental remediation activities in 2002. PECO cannot predict whether it will incur other significant liabilities for any additional investigation and remediation costs at these or additional sites identified by PECO, environmental agencies or others, or whether such costs will be recoverable from third parties. Security Issues and Other Impacts of Terrorist Actions. The events of September 11, 2001 have affected PECO's operating procedures and costs and are expected to affect the cost and availability of the insurance coverages that PECO carries. PECO has initiated security measures to safeguard its employees and critical operations and is actively participating in industry initiatives to identify methods to maintain the reliability of its delivery systems. It is expected that governmental authorities will be working to ensure that emergency plans are in place and that critical infrastructure vulnerabilities are addressed. The electric utility industry is proposing security guidelines rather than government mandated standards to protect critical infrastructures. It is not known if Federal standards will be issued to the electric or gas industries. PECO is evaluating enhanced security measures at certain critical locations, enhanced response and recovery plans and assessing longer term design changes and redundancy measures. These measures will involve additional expense to develop and implement. PECO carries property damage and liability insurance for its properties and operations. As a result of significant changes in the insurance marketplace, due in part to the September 11, 2001 terrorist acts, the available coverage and limits may be less than the amount of insurance obtained in the past, and the recovery for losses due to terrorists acts may be limited. PECO is self-insured to the extent that any losses may exceed the amount of insurance maintained. Damage to PECO's properties could disrupt the transmission or distribution 81 electricity and significantly and adversely affect results of operations. PECO cannot predict the effects on operations of the availability of property damage and liability coverage or any disruptions to its delivery facilities. NEW ACCOUNTING PRONOUNCEMENTS In 2001, the FASB issued SFAS No. 141, SFAS No. 142, SFAS No. 143 and SFAS No. 144. SFAS No. 141 requires that all business combinations be accounted for under the purchase method of accounting and establishes criteria for the separate recognition of intangible assets acquired in business combinations. SFAS No. 141 is effective for business combinations initiated after June 30, 2001. SFAS No. 142 establishes new accounting and reporting standards for goodwill and intangible assets. SFAS No. 142 is effective as of January 1, 2002. Under SFAS No. 142, effective January 1, 2002, goodwill recorded is no longer subject to amortization. After January 1, 2002, goodwill will be subject to an assessment for impairment using a two-step fair value based test, the first step of which must be performed at least annually, or more frequently if events or circumstances indicate that goodwill might be impaired. The first step compares the fair value of a reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step compares the carrying amount of the goodwill to the fair value of the goodwill. If the fair value of goodwill is less than the carrying amount, an impairment loss would be reported as a reduction to goodwill and a charge to operating expense, except at the transition date, when the loss would be reflected as a cumulative effect of a change in accounting principle. As of December 31, 2001, PECO does not have any Goodwill reflected on its Consolidated Balance Sheets and does not expect the effect of adopting SFAS No. 142 to materially affect the results of operations. As a result of the corporate restructuring in January 2001, all of PECO's goodwill was transferred to Enterprises. SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. PECO expects to adopt SFAS No. 143 on January 1, 2003. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. PECO is currently in the process of evaluating the impact of SFAS No. 143 on its financial statements. SFAS No. 144 establishes accounting and reporting standards for both the impairment and disposal of long-lived assets. This statement is effective for fiscal years beginning after December 15, 2001 and provisions of this statement are generally applied prospectively. PECO is in the process of evaluating the impact of SFAS No. 144 on its financial statements, and does not expect the impact to be material. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK EXELON The information required by this Item is incorporated herein by reference to the information appearing under the subheading "Quantitative and Qualitative Disclosures About 82 Market Risk" under "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Exhibit 99-2 to Exelon's Current Report on Form 8-K dated February 28, 2002. COMED ComEd is exposed to market risks associated with credit, interest rates and commodity price. The inherent risk in market sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, counterparty credit, and interest rates. Exelon's corporate Risk Management Committee (RMC) sets forth risk management philosophy and objectives for Exelon and its subsidiaries through a corporate policy, and establishes procedures for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of derivative activity and risk exposures. The RMC is chaired by Exelon's chief risk officer and includes the chief financial officer, general counsel, treasurer, vice president of corporate planning and officers from each of the business units. The RMC reports to the board of directors on the scope of ComEd's derivative activities. CREDIT RISK ComEd is obligated to provide service to all electric customers within its franchised territories, and, as a result, has a broad customer base. For the year ended December 31, 2001, ComEd's ten largest customers represented approximately 3% of its retail electric revenues. ComEd manages credit risk using credit and collection policies which are regulated by the ICC. INTEREST RATE RISK ComEd uses a combination of fixed rate and variable rate debt to reduce interest rate exposure. Interest rate swaps may be used to adjust exposure when deemed appropriate based upon market conditions. ComEd also utilizes forward-starting interest rate swaps and treasury rate locks to lock in interest rate levels in anticipation of future financing. These strategies are employed to maintain the lowest cost of capital. As of December 31, 2001, a hypothetical 10% increase in the interest rates associated with variable rate debt would result in a $1 million decrease in pre-tax earnings for 2002. ComEd has entered into an interest rate swap to manage interest rate exposure associated with a $235 million fixed-rate obligation. In December 2001, ComEd entered into forward-starting interest rate swaps, with an aggregate notional amount of $250 million in anticipation of the issuance of debt in the first quarter of 2002. At December 31, 2001, these interest rate swaps had an aggregate fair market value exposure of $1 million based on the present value difference between the contract and market rates at December 31, 2001. The aggregate fair value exposure of the interest rate swaps that would have resulted from a hypothetical 50 basis point decrease in the spot yield at December 31, 2001 is estimated to be $7 million. If these derivative instruments had been terminated at December 31, 2001, this estimated fair value represents the amount that would be paid by ComEd to the counterparties. The aggregate fair value exposure of the interest rate swaps that would have resulted from a hypothetical 50 basis point increase in the spot yield at December 31, 2001 is estimated to be $4 million. If these derivative instruments had been terminated at December 31, 2001, this estimated fair value represents the amount to be paid by the counterparties to ComEd. 83 In March 2002, ComEd settled the $250 million of forward-starting interest rate swaps and paid $6 million to the counterparty. ComEd also entered into forward-starting interest rate swaps with an aggregate notional amount of $175 million in anticipation of the issuance of debt in the second half of 2002. COMMODITY PRICE RISK As part of the corporate restructuring, ComEd entered into a PPA with Generation to meet its retail customer obligations at fixed prices. ComEd's principal exposure to commodity price risk is in relation to revenues collected from customers who elect the power purchase option at market-based prices, and CTC revenues which are calculated to provide the customer with a credit for the market price for electricity. ComEd has performed a sensitivity analysis to determine the net impact of a 10% decrease in the average around-the-clock market price of electricity. Because the decrease in revenues from customers electing the power purchase option is significantly offset by increased CTC revenues, ComEd does not believe that its exposure to such a market price decrease would be material. PECO PECO is exposed to market risks associated with credit and interest rates. The inherent risk in market sensitive instruments and positions is the potential loss arising from adverse changes in counterparty credit and interest rates. Exelon's corporate RMC sets forth risk management philosophy and objectives through a corporate policy, and establishes procedures for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of derivative activity and risk exposures. As a result of the PPA with Generation, PECO does not believe it is subject to material commodity price risk. CREDIT RISK PECO is obligated to provide service to all electric customers within its franchised territory. As a result, PECO has a broad customer base. For the year ended December 31, 2001, PECO's ten largest customers represented approximately 10% of its retail electric revenues. Credit risk for PECO is managed by its credit and collection policies, which is consistent with state regulatory requirements. Under the Competition Act, licensed entities, including alternate electric generating 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. Currently, there are no third parties providing billing of PECO's charges to customers or advanced metering. However, if this occurs, PECO would be subject to credit risk related to the ability of the third parties to collect such receivables from the customers. 84 INTEREST RATE RISK PECO uses a combination of fixed rate and variable rate debt to reduce interest rate exposure. Interest rate swaps may be used to adjust exposure when deemed appropriate based upon market conditions. PECO also utilizes forward-starting interest rate swaps and treasury rate locks to lock in interest rate levels in anticipation of future financing. These strategies are employed to maintain the lowest cost of capital. As of December 31, 2001, a hypothetical 10% increase in the interest rates associated with variable rate debt would not have a material impact on pre-tax earnings for 2002. PECO has entered into interest rate swaps to manage interest rate exposure associated with the floating rate series of transition bonds issued to securitize PECO's stranded cost recovery. At December 31, 2001, these interest rate swaps had an aggregate fair market value exposure of $19 million based on the present value difference between the contract and market rates at December 31, 2001. The aggregate fair value exposure of the interest rate swaps that would have resulted from a hypothetical 50 basis point decrease in the spot yield at December 31, 2001 is estimated to be $23 million. If these derivative instruments had been terminated at December 31, 2001, this estimated fair value represents the amount that would be paid by PECO to the counterparties. The aggregate fair value exposure of the interest rate swaps that would have resulted from a hypothetical 50 basis point increase in the spot yield at December 31, 2001 is estimated to be $15 million. If these derivative instruments had been terminated at December 31, 2001, this estimated fair value represents the amount to be paid by PECO to the counterparties. In 1999, PECO entered into interest rate swaps relating to the Class A-3 and Class A-5 Series 1999-A Transition Bonds in the aggregate notional amount of $1.1 billion with an average interest rate of 6.65%. PECO also entered into forward-starting interest rate swaps relating to these two classes of floating rate transition bonds in the aggregate notional amount of $1.1 billion with an average interest rate of 6.01%. In connection with the refinancing of a portion of the two floating rate series of transition bonds in the first quarter of 2001, PECO settled $318 million of a forward-starting interest rate swap, resulting in a $6 million gain which is reflected in other income and deductions. Also, in connection with the refinancing, PECO settled a portion of the interest rate swaps and the remaining portion of the forward-starting interest rate swaps resulting in gains of $25 million, which were deferred and are being amortized over the expected remaining lives of the related debt. In February 2000, PECO entered into forward-starting interest rate swaps for a notional amount of $1 billion in anticipation of the issuance of $1 billion of Transition Bonds in the second quarter of 2000. In May 2000, PECO settled these forward-starting interest rate swaps and paid the counterparties $13 million which was deferred and is being amortized over the life of the Transition Bonds as an increase in interest expense. 85 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA EXELON The information required by this Item is incorporated herein by reference to the Consolidated Statements of Income for the years 2001, 2000 and 1999; Consolidated Statements of Cash Flows for the years 2001, 2000 and 1999; Consolidated Balance Sheets as of December 31, 2001 and 2000; Consolidated Statements of Changes in Shareholders' Equity for the years 2001, 2000 and 1999 and Consolidated Statements of Comprehensive Income for the years 2001, 2000 and 1999; and Notes to Consolidated Financial Statements appearing in Exhibit 99-4 to Exelon's Current Report on Form 8-K dated February 28, 2002. 86 ComEd REPORT OF INDEPENDENT ACCOUNTANTS To the Shareholders and Board of Directors of Commonwealth Edison Company: In our opinion, the consolidated financial statements listed in the index appearing under Item 14(a)(2)(i) present fairly, in all material respects, the financial position of Commonwealth Edison Company and Subsidiary Companies (ComEd) at December 31, 2001 and 2000, and the results of their operations and their cash flows for the year ended December 31, 2001 and for the periods from October 20, 2000 to December 31, 2000 and from January 1, 2000 to October 19, 2000, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 14(a)(2)(ii) for the years ended December 31, 2001 and 2000, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of ComEd's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 3 to the consolidated financial statements, effective October 20, 2000, Exelon Corporation acquired Unicom Corporation, the parent company of ComEd at that date, in a business combination accounted for as a purchase. As a result of the acquisition, the consolidated financial information for the period after the acquisition is presented on a different cost basis than that for the periods before the acquisition and therefore, is not comparable. As discussed in Note 2, as part of a corporate restructuring undertaken on January 1, 2001 by Exelon Corporation, the parent company of ComEd, all of ComEd's generation-related and certain other operations, assets and liabilities of ComEd were transferred to affiliated companies of ComEd. As discussed in Note 1 to the consolidated financial statements, ComEd changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001. PricewaterhouseCoopers LLP Chicago, Illinois January 29, 2002, except for Note 19 for which the date is March 21, 2002. 87 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders of Commonwealth Edison Company: We have audited the consolidated statements of income, cash flows, comprehensive income and changes in shareholders' equity of Commonwealth Edison Company (an Illinois corporation) and Subsidiary Companies for the year ended December 31, 1999. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Commonwealth Edison Company and Subsidiary Companies for the year ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed under Item 14(a)(2)(ii) for the year ended December 31, 1999, is presented for the purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. Arthur Andersen LLP Chicago, Illinois January 31, 2000 88 COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME

For the For the period For the Year Ended Oct. 20 - Jan. 1- Year Ended Dec. 31, Dec. 31, Oct. 19, Dec. 31, (in millions) 2001 2000 2000 1999 ------------- ---- ---- ---- ---- OPERATING REVENUES Operating Revenues $ 6,125 $ 1,297 | $ 5,625 $ 6,793 Operating Revenues from Affiliates 81 13 | 77 -- ------- ------- | ------- ------- Total Operating Revenues 6,206 1,310 | 5,702 6,793 ------- ------- | ------- ------- OPERATING EXPENSES | | Fuel and Purchased Power 14 322 | 1,655 1,549 Purchased Power from Affiliate 2,656 -- | -- -- Operating and Maintenance 833 423 | 1,653 2,352 Operating and Maintenance from Affiliates 148 -- | -- -- Merger-Related Costs -- 14 | 53 -- Depreciation and Amortization 665 130 | 868 836 Taxes Other Than Income 296 83 | 425 507 ------- ------- | ------- ------- Total Operating Expenses 4,612 972 | 4,654 5,244 ------- ------- | ------- ------- OPERATING INCOME 1,594 338 | 1,048 1,549 ------- ------- | ------- ------- Other Income and Deductions | | Interest Expense (555) (127)| (469) (602) Interest Expense from Affiliates (10) -- | -- -- Distributions on Company-Obligated | Mandatorily Redeemable Preferred Securities of | Subsidiary Trusts Holding Solely the Company's | Subordinated Debt Securities (30) (6)| (24) (30) Interest Income from Affiliates 79 29 | 150 8 Other, Net 35 2 | 127 52 ------- ------- | ------- ------- Total Other Income and Deductions (481) (102)| (216) (572) ------- ------- | ------- ------- INCOME BEFORE INCOME TAXES AND EXTRAORDINARY ITEMS 1,113 236 | 832 977 INCOME TAXES 506 103 | 229 326 ------- ------- | ------- ------- INCOME BEFORE EXTRAORDINARY ITEMS 607 133 | 603 651 EXTRAORDINARY ITEMS (NET OF INCOME TAXES OF $2 AND $18 | FOR THE PERIODS ENDING OCT. 19, 2000 AND DEC. 31, 1999, | RESPECTIVELY) -- -- | (4) (28) ------- ------- | ------- ------- NET INCOME 607 133 | 599 623 PREFERRED AND PREFERENCE STOCK DIVIDENDS -- -- | 3 24 ------- ------- | ------- ------- NET INCOME ON COMMON STOCK $ 607 $ 133 | $ 596 $ 599 ======= ======= | ======= =======

See Notes to Consolidated Financial Statements 89 COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS

For the For the period For the Year Ended Oct. 20 - Jan. 1- Year Ended Dec. 31, Dec. 31 Oct. 19 Dec. 31, (in millions) 2001 2000 2000 1999 ------------- ---- ---- | ---- ---- | CASH FLOWS FROM OPERATING ACTIVITIES | | Net Income $ 607 $ 133 | $ 599 $ 623 Adjustments to reconcile Net Income to Net | Cash Flows provided by Operating Activities: | Depreciation and Amortization 665 174 | 1,012 902 Extraordinary Items (net of income taxes) -- -- | 4 28 (Gain)/loss on Forward Share Arrangements -- -- | (113) 44 Reversal of Provision for Revenue Refunds (15) -- | -- -- Provision for Uncollectible Accounts 42 16 | 30 87 Deferred Income Taxes 14 72 | 861 (1,456) Merger-Related Costs -- 14 | 53 -- Early Retirement and Separation Program -- -- | 28 (62) Midwest Independent System Operator Exit Fees (36) -- | -- -- Contribution to Environmental Trust -- -- | -- (250) Recovery of Coal Reserve Regulatory Assets -- -- | -- 198 Other Operating Activities (2) (69) | (163) 1 Changes in Working Capital: | Accounts Receivable 76 (37) | 96 (175) Inventories 16 97 | 17 (6) Accounts Payable, Accrued Expenses | & Current Liabilities 149 65 | (1,334) 1,331 Change in Receivables and Payables to Affiliates, net (166) -- | (10) (6) Other Current Assets 2 59 | (6) (16) ------- ------- | ------- ------- NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES 1,352 524 | 1,074 1,243 ------- ------- | ------- ------- CASH FLOWS FROM INVESTING ACTIVITIES | | Investment in Plant (839) (196) | (1,210) (1,337) Plant Removals, net (30) (11) | (14) (75) Sales of Generating Plants -- -- | -- 4,886 Proceeds from Nuclear Decommissioning Trust Funds -- 288 | 1,251 1,593 Investment in Nuclear Decommissioning Trust Funds -- (377) | (1,290) (1,683) Change in Receivables from Affiliates 417 (441) | 288 (2,209) Other Investments -- (63) | 139 (37) Other Investing Activities 11 -- | 9 8 ------- ------- | ------- ------- NET CASH FLOWS (USED IN) PROVIDED BY INVESTING ACTIVITIES (441) (800) | (827) 1,146 ------- ------- | ------- ------- CASH FLOWS FROM FINANCING ACTIVITIES | | Issuance of Long-Term Debt, net of issuance costs -- -- | 450 -- Common Stock Repurchases -- -- | (153) (115) Retirement of Long-Term Debt (542) (84) | (755) (1,558) Change in Short-Term Debt -- -- | (5) (272) Redemption of Preferred Securities of Subsidiaries -- -- | (71) (534) Change in Restricted Cash 19 50 | 175 2,778 Dividends on Capital Stock (483) (95) | (260) (392) Common Stock Forward Repurchases -- -- | (67) (813) Nuclear Fuel Lease Principal Payments -- -- | (270) (255) Other Financing Activities (23) -- | -- -- ------- ------- | ------- ------- NET CASH FLOW USED IN FINANCING ACTIVITIES (1,029) (129) | (956) (1,161) ------- ------- | ------- ------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (118) (405) | (709) 1,228 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 141 546 | 1,255 27 ------- ------- | ------- ------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 23 $ 141 | $ 546 $ 1,255 ======= ======= | ======= =======

See Notes to Consolidated Financial Statements 90 COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS

at December 31, --------------- (in millions) 2001 2000 ------------- ---- ---- ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 23 $ 141 Restricted Cash 41 60 Accounts Receivable, net Customer 745 970 Other 87 234 Inventories, at average cost 56 186 Deferred Income Taxes 52 89 Receivables from Affiliates 95 468 Other 15 24 -------- -------- Total Current Assets 1,114 2,172 -------- -------- PROPERTY, PLANT AND EQUIPMENT, NET 7,351 7,657 DEFERRED DEBITS AND OTHER ASSETS Regulatory Assets 667 1,110 Nuclear Decommissioning Trust Funds -- 2,669 Investments 64 152 Goodwill, net 4,902 4,766 Receivables from Affiliates 1,314 1,316 Other 304 356 -------- -------- Total Deferred Debits and Other Assets 7,251 10,369 -------- -------- TOTAL ASSETS $ 15,716 $ 20,198 ======== ======== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Long-Term Debt Due Within One Year $ 849 $ 348 Accounts Payable 144 597 Accrued Expenses 63 148 Accrued Interest 165 149 Accrued Taxes 146 79 Payables to Affiliates 307 -- Customer Deposits 90 73 Other 122 329 -------- -------- Total Current Liabilities 1,886 1,723 -------- -------- LONG-TERM DEBT 5,850 6,882 DEFERRED CREDITS AND OTHER LIABILITIES Deferred Income Taxes 1,671 1,837 Unamortized Investment Tax Credits 55 59 Nuclear Decommissioning Liability for Retired Plants -- 1,301 Pension Obligations 151 285 Non-Pension Postretirement Benefits Obligation 146 315 Spent Fuel Obligation -- 810 Payables to Affiliates 297 -- Other 248 475 -------- -------- Total Deferred Credits and Other Liabilities 2,568 5,082 -------- -------- COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING THE COMPANY'S SUBORDINATED DEBT SECURITIES 329 328 COMMITMENTS AND CONTINGENCIES SHAREHOLDERS' EQUITY Common Stock 2,048 2,678 Preference Stock 7 7 Other Paid in Capital 5,057 5,388 Receivable from Parent (937) -- Retained Earnings 257 133 Treasury Stock, at cost (1,344) (2,023) Accumulated Other Comprehensive Income (5) -- -------- -------- Total Shareholders' Equity 5,083 6,183 -------- -------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 15,716 $ 20,198 ======== ========

See Notes to Consolidated Financial Statements 91 COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

Accumulated Preferred and Other Receivable Other Total Common Preference Paid-in from Retained Comprehensive Treasury Shareholders' (in millions) Stock Stock Capital Parent Earnings Income Stock Equity ------------- ----- ----- ------- ------ -------- ------ ----- ------ BALANCE, DECEMBER 31, 1998 $ 2,678 $ 524 $ 2,208 $ -- $ 177 $ -- $ (7) $ 5,580 Net Income -- -- -- -- 623 -- -- 623 Preferred and Preference Stock Redemptions -- (515) -- -- -- -- -- (515) Capital Stock and Warrant Expense -- -- 3 -- (16) -- -- (13) Common Stock Dividends -- -- -- -- (342) -- -- (342) Preferred and Preference Stock Dividends -- -- -- -- (9) -- -- (9) Common Stock Repurchases -- -- -- -- -- -- (20) (20) Other Comprehensive Income, net of income taxes of $5 -- -- -- -- -- 8 -- 8 ------- ------- ------- ------- -------- ---- ------- ------- BALANCE, DECEMBER 31, 1999 $ 2,678 $ 9 $ 2,211 $ -- $ 433 $ 8 $ (27) $ 5,312 Net Income -- -- -- -- 599 -- -- 599 Preferred and Preference Stock Redemptions -- (2) -- -- -- -- -- (2) Capital Stock Expense -- -- -- -- (1) -- -- (1) Common Stock Dividends -- -- -- -- (238) -- -- (238) Preferred and Preference Stock Dividends -- -- -- -- (1) -- -- (1) Common Stock Repurchases -- -- -- -- -- -- (153) (153) Stock Forward Repurchase Contract -- -- -- -- -- -- (993) (993) Other Comprehensive Income, net of income taxes of $0 -- -- -- -- -- (2) -- (2) ----------------------------------------------------------------------------------------------------------------------- BALANCE, OCTOBER 19, 2000 $ 2,678 $ 7 $ 2,211 $ -- $ 792 $ 6 $(1,173) 4,521 Net Income -- -- -- -- 133 -- -- 133 Merger Fair Value Adjustments -- -- 3,177 -- (792) (6) -- 2,379 Common Stock Repurchases -- -- -- -- -- -- (850) (850) ------- ------- ------- ------- -------- ---- ------- ------- BALANCE, DECEMBER 31, 2000 $ 2,678 $ 7 $ 5,388 $ -- $ 133 $ -- $(2,023) $ 6,183 Net Income -- -- -- -- 607 -- -- 607 Capital Contribution from Parent -- -- 1,062 (937) -- -- -- 125 Retirement of Treasury Shares (630) -- (1,393) -- -- -- 2,023 -- Merger Fair Value Adjustments -- -- 24 -- -- -- -- 24 Corporate Restructuring -- -- (24) -- -- -- (1,344) (1,368) Common Stock Dividends -- -- -- -- (483) -- -- (483) Other Comprehensive Income, net of income taxes of $1 -- -- -- -- -- (5) -- (5) ------- ------- ------- ------- -------- ---- ------- ------- BALANCE, DECEMBER 31, 2001 $ 2,048 $ 7 $ 5,057 $ (937) $ 257 $ (5) $(1,344) $ 5,083 ======= ======= ======= ======= ======= ==== ======= =======

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Year Ended For the Period For the Year Ended -------------- ------------------ December 31, Oct. 20-Dec. 31, | Jan.1 -Oct. 19 December 31, (in millions) 2001 2000 | 2000 1999 ------------- ---- ---- | ---- ---- | Net Income $ 607 $ 133 | $ 599 $ 623 Other Comprehensive Income | Cash Flow Hedge Fair Value Adjustment, | net of income taxes of $0 (1) -- | -- -- Foreign Currency Translation Adjustment, | net of income taxes of $0 (1) -- | -- -- Unrealized Gain (Loss) on Marketable Securities, | net of income taxes of $1, $0 and $5, respectively (3) -- | (2) 8 Merger Fair Value Adjustment -- (6) | -- -- ----- ----- | ----- ----- Total Other Comprehensive Income (5) (6) | (2) 8 ----- ----- | ----- ----- Total Comprehensive Income $ 602 $ 127 | $ 597 $ 631 ===== ===== | ===== =====

See Notes to Consolidated Financial Statements 92 Commonwealth Edison Company and Subsidiary Companies NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in millions, unless otherwise noted) 1. Significant Accounting Policies DESCRIPTION OF BUSINESS As a result of the corporate restructuring, effective January 1, 2001 (see Note 2 - Corporate Restructuring), Commonwealth Edison Company's (ComEd's) generation and other competitive businesses were separated from its regulated energy delivery business. As a result, the operations of ComEd consist of its retail electricity distribution and transmission business to 3.6 million retail customers. ComEd's retail electric service territories are located principally in northern Illinois including metropolitan Chicago, spanning an area of approximately 11,300 square miles. BASIS OF PRESENTATION The consolidated financial statements of ComEd include the accounts of ComEd, Commonwealth Edison Company of Indiana, Inc. , Edison Development Canada Inc. , ComEd Financing I and ComEd Financing II , ComEd Funding LLC (ComEd Funding), and ComEd Transitional Funding Trust (ComEd Funding Trust). All significant intercompany transactions have been eliminated. Although the accounts of ComEd Funding and ComEd Funding Trust, which are Special Purpose Entities (SPEs), are included in the consolidated financial statements, as required by generally accepted accounting principles (GAAP), ComEd Funding and ComEd Funding Trust are separate legal entities from ComEd. The assets of the SPEs are not available to creditors of ComEd and the transitional property held by the SPEs are not assets of ComEd. Accounting policies for regulated operations are in accordance with those prescribed by the regulatory authorities having jurisdiction, principally the Illinois Commerce Commission (ICC), the Federal Energy Regulatory Commission (FERC) and the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA). ComEd, a regulated electric utility, is a principal subsidiary of Exelon Corporation (Exelon), which owns 99.9% of ComEd common stock. ComEd was the principal subsidiary of Unicom Corporation (Unicom) prior to the merger with Exelon. See Note 3 - Merger. The merger was accounted for using the purchase method of accounting in accordance with GAAP. The effects of the purchase method are reflected on the financial statements of ComEd as of the merger date. Accordingly, the financial statements presented for the period after the merger reflect a new basis of accounting. ComEd's financial statements for 2000, separated by a bold black line, are presented for periods prior to and subsequent to the merger. ACCOUNTING FOR THE EFFECTS OF REGULATION ComEd accounts for its regulated electric operations in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," requiring ComEd to record in the financial statement the effects of the rate regulation to which these operations are currently subject. Use of SFAS No. 71 is applicable to the utility operations of ComEd that meet the following criteria: (1) third-party regulation of rates; (2) cost-based rates; and (3) a reasonable assumption that all costs will be recoverable from customers through rates. ComEd believes that it is probable that regulatory assets associated with these operations will be recovered. If a separable portion of ComEd's business no longer meets the provisions of SFAS No. 71, ComEd is required to eliminate the financial statement effects of regulation for that portion. 93 USE OF ESTIMATES The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates have been made in the accounting for unbilled revenue, derivatives, environmental costs, retirement benefit costs and prior to the corporate restructuring nuclear decommissioning liabilities. REVENUES Operating revenues are generally recorded as service is rendered or energy is delivered to customers. At the end of each month, ComEd accrues an estimate for the unbilled amount of energy delivered or services provided to its customers. NUCLEAR FUEL Prior to the corporate restructuring in which ComEd's nuclear generating stations were transferred to Exelon Generation Company, LLC (Generation) (see Note 2 - Corporate Restructuring), the cost of nuclear fuel was capitalized and charged to fuel expense using the unit of production method. Estimated costs of nuclear fuel storage and disposal were charged to expense as the related fuel was consumed. DEPRECIATION, AMORTIZATION AND DECOMMISSIONING Depreciation is provided over the estimated service lives of property, plant, and equipment on a straight line basis. Annual depreciation provisions for financial reporting purposes, expressed as a percentage of average service life for each asset category are presented below:

Asset Category 2001 2000 | 1999 -------------- ---- ---- | ---- | Electric -- Transmission and Distribution 5.20% 5.83% | 3.24% Electric -- Generation -- 4.83% | 2.20% Other Property and Equipment 5.95% 7.31% | 5.71% ---- ---- | ----

Amortization of regulatory assets is provided over the recovery period specified in the related legislation or regulatory agreement. See Note 5 - Regulatory Issues - regarding the regulatory accounting treatment for the nuclear generating stations transferred to Generation. Goodwill associated with the merger was amortized on a straight line basis over 40 years in 2001 and 2000. Accumulated amortization of goodwill was $149 and $23 million at December 31, 2001 and 2000, respectively. Effective January 1, 2002, under SFAS No. 142 "Goodwill and Other Intangible Assets"(SFAS 142), goodwill recorded by ComEd is no longer subject to amortization. See the New Accounting Pronouncement section of this note. ComEd's estimate of the costs for decommissioning nuclear generating stations transferred to Generation is currently included in regulated rates. Prior to the corporate restructuring the amounts recovered from customers were deposited in trust accounts and invested for funding of future costs for current and retired plants. ComEd accounted for the current period cost of decommissioning by recording a charge to depreciation expense and a corresponding liability in accumulated depreciation for its operating nuclear units and a reduction to regulatory assets for its retired units. Subsequent to the corporate restructuring, amounts recovered from customers are remitted to Generation. CAPITALIZED INTEREST ComEd uses SFAS No. 34, "Capitalization of Interest Costs", to calculate the costs during construction of debt funds used to finance its non-regulated construction projects. ComEd recorded capitalized interest of $0 million, $5 million and $22 million in 2001, 2000 and 1999, respectively. 94 Allowance for Funds Used During Construction (AFUDC) is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC of $17 million, $19 million and $22 million in 2001, 2000 and 1999, respectively, was recorded as a charge to Construction Work in Progress and as a non-cash credit to AFUDC which is included in Other Income and Deductions. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities. INCOME TAXES Deferred Federal and state income taxes are provided on all significant temporary differences between book bases and tax bases of assets and liabilities, transactions that reflect taxable income in a year different from book income and tax carryforwards. Investment tax credits previously used for income tax purposes have been deferred on ComEd's Consolidated Balance Sheets and are recognized in book income over the life of the related property. ComEd files a consolidated Federal and state income tax returns with Exelon, and was previously included in Unicom's consolidated income tax returns. Current and deferred income taxes of the consolidated group are allocated to ComEd as if ComEd filed separate income tax returns. GAINS AND LOSSES ON REACQUIRED DEBT Recoverable gains and losses on reacquired debt related to regulated operations are deferred and amortized to interest expense over the period consistent with rate recovery for ratemaking purposes. In 2000 and 1999, prior to the corporate restructuring, gains and losses on reacquired debt were recognized in ComEd's Consolidated Statements of Income as incurred. COMPREHENSIVE INCOME Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to shareholders. CASH AND CASH EQUIVALENTS ComEd considers all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents. RESTRICTED CASH Restricted cash reflects unused cash proceeds from the issuance of the transitional trust notes and escrowed cash to be applied to the principal and interest payment on the transitional trust notes. MARKETABLE SECURITIES Marketable securities are classified as available-for-sale securities and are reported at fair value, with the unrealized gains and losses, net of tax, reported in other comprehensive income. Prior to the corporate restructuring (see Note 2 - Corporate Restructuring), unrealized gains and losses on marketable securities held in the nuclear decommissioning trust funds were reported in accumulated depreciation for operating units and as a reduction of regulatory assets for retired units. At December 31, 2001 and 2000, ComEd had no held-to-maturity or trading securities. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is recorded at cost. ComEd evaluates the carrying value of property, plant and equipment and other long-term assets based upon current and anticipated undiscounted cash flows, and recognizes an impairment when it is probable that such estimated cash flows will be less than the carrying value of the asset. Measurement of the amount of impairment, if any, is based upon the difference between carrying value and fair value. The cost of maintenance, repairs and minor replacements of property are charged to maintenance expense as incurred. Upon retirement, the cost of regulated property plus removal costs less salvage, are charged to accumulated depreciation in accordance with the provisions of SFAS No. 71. For unregulated property, the cost and accumulated depreciation of property, plant and equipment 95 retired or otherwise disposed of are removed from the related accounts and included in the determination of the gain or loss on disposition. CAPITALIZED SOFTWARE COSTS Costs incurred during the application development stage of software projects which are developed or obtained for internal use are capitalized. At December 31, 2001 and 2000, net capitalized software costs totaled $104 million and $150 million, respectively, reflecting $17 million and $4 million in accumulated amortization, respectively. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, not to exceed 10 years. Certain capitalized software is being amortized over 15 years pursuant to regulatory approval. DERIVATIVE FINANCIAL INSTRUMENTS ComEd accounts for derivative financial instruments pursuant to SFAS No. 133, "Accounting for Derivatives and Hedging Activities" (SFAS 133). Under the provisions of SFAS 133, all derivatives are recognized on the balance sheet at their fair value unless they qualify for a normal purchases and normal sales exception. Changes in the fair value of the derivative financial instrument are recognized in earnings unless specific hedge accounting criteria are met. A derivative financial instrument can be designated as a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge), or a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). Changes in the fair value of a derivative that is highly effective as, and is designated and qualifies as a fair value hedge, along with the gain or loss on the hedged asset or liability that is attributable to the hedged risk, are recorded in earnings. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as a cash flow hedge are recorded in other comprehensive income, until earnings are affected by the variability of cash flows being hedged. In connection with Exelon's Risk Management Policy, ComEd enters into derivatives to effectively convert fixed rate debt to floating rate debt, manage its exposure to fluctuations in interest rates related to planned future debt issuances prior to their actual issuance, as well as exposure to changes in the fair value of outstanding debt which is planned for early retirement. Prior to the adoption of SFAS No. 133, ComEd applied hedge accounting only if the derivative reduced the risk of the underlying hedged item and was designated at the inception of the hedge, with respect to the hedged item. ComEd recognized any gains or losses on these derivatives when the underlying physical transaction affected earnings. NEW ACCOUNTING PRONOUNCEMENTS In 2001, the FASB issued SFAS No. 141, "Business Combinations" (SFAS No. 141), SFAS No. 142, No. 143, "Asset Retirement Obligations" (SFAS No. 143), and SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). SFAS No. 141 requires that all business combinations be accounted for under the purchase method of accounting and establishes criteria for the separate recognition of intangible assets acquired in business combinations. SFAS No. 141 is effective for business combinations initiated after June 30, 2001. SFAS No. 142 establishes new accounting and reporting standards for goodwill and intangible assets. ComEd adopted SFAS No. 142 as of January 1, 2002. Under SFAS No. 142, effective January 1, 2002, goodwill recorded by ComEd is no longer subject to amortization. After January 1, 2002, goodwill will be subject to an assessment for impairment using a two-step fair value based test, the first step of which must be performed at least annually, or more frequently if events or circumstances indicate that goodwill might be impaired. The first step compares the fair value of a reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step compares the carrying amount of the goodwill to the fair value of the goodwill. If the 96 fair value of goodwill is less than the carrying amount, an impairment loss would be reported as a reduction to goodwill and a charge to operating expense, except at the transition date, when the loss would be reflected as a cumulative effect of a change in accounting principle. As of December 31, 2001, ComEd's Consolidated Balance Sheets reflected approximately $4.9 billion in Goodwill, net of accumulated amortization. Annual amortization of goodwill of $126 million was discontinued upon adoption of SFAS No. 142. In the first quarter of 2002, ComEd has completed the first step of the transitional impairment analysis, which indicated that its goodwill is not impaired. SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. This statement is effective for fiscal years beginning after June 15, 2002 with initial application as of the beginning of the fiscal year. ComEd is in the process of evaluating the impact of SFAS No. 143 on its financial statements. SFAS No. 144 establishes accounting and reporting standards for both the impairment and disposal of long-lived assets. This statement is effective for fiscal years beginning after December 15, 2001 and provisions of this statement are generally applied prospectively. ComEd is in the process of evaluating the impact of SFAS No. 144 on its financial statements and does not expect the impact to be material. RECLASSIFICATIONS Certain prior year amounts have been reclassified for comparative purposes. These reclassifications had no effect on net income or shareholders' equity. 2. Corporate Restructuring During January 2001, Exelon undertook a corporate restructuring to separate its generation and other competitive businesses from its regulated energy delivery businesses at ComEd and PECO. As part of the restructuring, the generation-related operations and assets and liabilities of ComEd were transferred to Generation. Additionally, certain operations and assets and liabilities of ComEd were transferred to Exelon Business Services Company (BSC). As a result, effective January 1, 2001, the operations of ComEd consist of its retail electricity distribution and transmission business in northern Illinois. The corporate restructuring had the following effect on the Condensed Consolidated Balance Sheets of ComEd: Decrease in Assets: Current Assets $ (397) Property, Plant and Equipment, net (781) Investments (85) Other Noncurrent Assets (2,629) Decrease in Liabilities: Current Liabilities 799 Long-Term Debt -- Deferred Income Taxes (24) Other Noncurrent Liabilities 2,212 ------- Net Assets Transferred $ (905) ======= 97 Consideration, based on the net book value of the net assets transferred, was as follows: Treasury Stock Received $ 1,344 Other Paid in Capital 24 Notes Payable - Affiliates (463) ------- $ 905 ======= In connection with the restructuring, ComEd assigned its respective rights and obligations under various power purchase and fuel supply agreements to Generation. Additionally, ComEd entered into a power purchase agreement (PPA) with Generation. Under the PPA between ComEd and Generation, Generation has agreed to supply all of ComEd's load requirements through 2004. Prices for this energy vary depending upon the time of day and month of delivery. During 2005 and 2006, ComEd's PPA is a partial requirements agreement under which ComEd will purchase all of its required energy and capacity from Generation, up to the available capacity of the nuclear generating plants formerly owned by ComEd and transferred to Generation. Under the terms of the PPA, Generation is responsible for obtaining any required transmission service. The PPA also specifies that prior to 2005, ComEd and Generation will jointly determine and agree on a market-based price for energy delivered under the PPA for 2005 and 2006. In the event that the parties cannot agree to market-based prices for 2005 and 2006 prior to July 1, 2004, ComEd has the option of terminating the PPA effective December 31, 2004. ComEd will obtain any additional supply required from market sources in 2005 and 2006, and subsequent to 2006, will obtain all of its supply from market sources, which could include Generation. The obligation for decommissioning ComEd's nuclear facilities and the related trust fund assets were transferred to Generation concurrently with the transfer of the generating plants and the related Nuclear Regulatory Commission (NRC) operating licenses as of January 1, 2001. ComEd had historically accounted for the current period's cost of decommissioning by recording a charge to depreciation expense and a corresponding liability in accumulated depreciation for its operating units and a reduction to regulatory assets for retired units (in current year dollars) on a straight-line basis over the NRC operating license life of the plants. As of December 31, 2000, ComEd's cumulative liability of $2.1 billion was recorded as a component of accumulated depreciation. Additionally, a $1.3 billion liability representing the present value of the estimated cost of decommissioning nuclear units previously retired was recorded as a long- term liability. These liabilities, as well as investments in trust fund assets of $2.7 billion to fund the costs of decommissioning, were transferred to Generation. Additionally, as part of the corporate restructuring, ComEd's liability to the U.S. Department of Energy (DOE) for payment of its one-time fee for spent nuclear fuel disposal was transferred to Generation. As of December 31, 2000, this liability, including accrued interest, was $810 million. Also, provisions for nuclear insurance were assumed by Generation under terms and conditions commensurate with those previously borne by ComEd. 98 3. Merger On October 20, 2000, Exelon became the parent corporation of PECO Energy Company (PECO) and ComEd as a result of the completion of the transactions contemplated by an Agreement and Plan of Exchange and Merger, as amended (Merger Agreement), among PECO, Unicom Corporation (Unicom) and Exelon. Pursuant to the Merger Agreement, Unicom merged with and into Exelon (Merger). In the Merger, each share of the outstanding common stock of Unicom was converted into 0.875 shares of common stock of Exelon plus $3.00 in cash. As a result of the Merger, Unicom ceased to exist and its subsidiaries, including ComEd, became subsidiaries of Exelon. The Merger was accounted for using the purchase method of accounting. Purchase transactions resulting in one entity becoming substantially wholly owned by the acquiror establish a new basis of accounting in the acquired entity's records for the purchased assets and liabilities. Thus, the purchase price has been allocated to the underlying assets purchased and liabilities assumed based on their estimated fair values at the acquisition date. As a result of the application of the purchase method of accounting, the following fair value adjustments as adjusted to reflect final purchase price allocation, including the elimination of accumulated depreciation, retained earnings and other comprehensive income, were recorded in ComEd's Consolidated Balance Sheets:

Total ----- Increase (Decrease) in Assets: Property, Plant and Equipment, net $(4,791) Goodwill 5,051 Other Assets (254) (Increase) Decrease in Liabilities and Shareholders' Equity: Deferred Income Taxes 1,756 Unamortized Investment Tax Credits 401 Merger Severance Obligation (327) Pension and Postretirement Benefit Obligations 471 Long-Term Debt and Preferred Securities 116 Other Liabilities (20) Other Paid in Capital (3,201) Retained Earnings 792 Accumulated Other Comprehensive Income 6 -------

Reductions to the carrying value of property, plant and equipment balances primarily reflect the fair value of the nuclear generating assets based on discounted cash flow analyses and independent appraisals. Adjustments to deferred income taxes, long-term debt and preferred securities, and other assets and liabilities were recorded based on the estimate of fair market value. Reductions to unamortized investment tax credits represents the adjustment of nuclear generating asset investment tax credits to fair value. Merger severance obligations relating to ComEd's employee exit costs were recorded in the purchase price allocation. Reductions to pension and postretirement benefit obligations primarily reflect elimination of unrecognized net actuarial gains, prior service costs and transition obligations. Goodwill represents the purchase price allocation to ComEd of the cost in excess of net assets acquired in the Merger, which was amortized over a forty year period for 2000 and 2001. Annual amortization of goodwill related to the Merger of $126 million was discontinued upon adoption of SFAS 142. Goodwill associated with the Merger increased by $262 million in 2001 as a result of the finalization of the purchase price allocation. The adjustment resulted primarily from the after-tax effects of a reduction of the regulatory asset for decommissioning retired nuclear plants, additional employee separation costs and the finalization of other purchase price allocations. 99 MERGER-RELATED COSTS In connection with the Merger, ComEd recorded certain reserves for restructuring costs. Costs incurred prior to the Merger were charged to expense. Costs incurred subsequent to the Merger were reflected as part of the application of purchase accounting and did not affect results of operations. ComEd's Merger-related costs charged to expense in 2000 were $67 million consisting of $26 million of direct incremental costs and $41 million for employee costs. Direct incremental costs represent expenses directly associated with completing the Merger, including professional fees, regulatory approval and other merger integration costs. Employee costs represent estimated severance payments provided under Exelon's Merger Separation Plan (MSP) for eligible employees whose positions were eliminated before October 20, 2000 due to integration activities of the merged companies. Included in the purchase price allocation is a liability for employee costs and liabilities for estimated costs of exiting business activities that were not compatible with the strategic business direction of Exelon of $36 million. During 2001, ComEd finalized its plans for consolidation of functions, including negotiation of an agreement with the union regarding severance benefits to union employees and recorded adjustments to the purchase price allocation. The employee liabilities are as follows:

Original 2001 Adjusted Estimate Adjustments Liabilities -------- ----------- ----------- Employee severance payments (a) $128 $ 25 $153 Actuarially determined pension and postretirement costs (b) 158 (13) 145 Relocation and other severance (a) 21 8 29 ---- ---- ---- Total ComEd - Employee Cost $307 $ 20 $327 ==== ==== ====

(a) The increase is a result of the identification in 2001 of additional positions to be eliminated. (b) The reduction results from lower estimated pension and post retirement welfare benefits reflecting revised actuarial estimates. The involuntary terminations are a result of merger integration and reengineering of processes, primarily in the areas of corporate support, generation, and energy delivery. During 2001 a portion of the liabilities that related to Generation employees were transferred to Generation as part of the corporate restructuring. Approximately 1,228 ComEd positions, reflecting the corporate restructuring, have been identified to be eliminated as a result of the Merger. ComEd anticipates that $85 million of employee costs will be funded from its pension and postretirement benefit plans and $92 million will be funded from general corporate funds. ComEd has terminated 399 employees as of December 31, 2001. The remaining positions are expected to be eliminated by the end of 2002. 100 The following table provides a reconciliation of the reserve for employee severance and relocation costs associated with the Merger: Employee severance and relocation reserve as of October 20, 2000 $ 149 Additional reserve 33 ----- Adjusted employee severance and relocation reserve 182 Payments to employees (October 2000-December 2001) (75) Restructuring transfer (45) ----- Employee severance and relocation reserve as of December 31, 2001, after restructuring 62 ===== 4. Fossil Plant Sale In December 1999, ComEd completed the sale of its fossil generating assets to Edison Mission Energy, an Edison International subsidiary (EME), for a cash purchase price of $4.8 billion. The fossil generating assets represented an aggregate generating capacity of approximately 9,772 megawatts. Just prior to the consummation of the fossil plant sale, ComEd transferred these assets to an affiliate, Unicom Investment, Inc. (Unicom Investment). In consideration for the transferred assets, Unicom Investment paid ComEd consideration totaling approximately $4.8 billion in the form of a demand note in the amount of approximately $2.4 billion and an interest-bearing note with a maturity of twelve years. Unicom Investment immediately sold the fossil plant assets to EME, in consideration of which Unicom Investment received approximately $4.8 billion in cash from EME. Immediately after its receipt of the cash payment from EME, Unicom Investment paid the demand note in full. Unicom Investment used the remainder of the cash received from EME to fund other business opportunities, including share repurchases. Of the cash received by ComEd, $1.8 billion was used to pay the costs and taxes associated with the fossil plant sale, including ComEd's contribution of $250 million of the proceeds to an environmental trust as required by Illinois legislation. The remainder of the demand note proceeds was available to ComEd to fund, among other things, transmission and distribution projects, nuclear generation station projects, and environmental and other initiatives. The sale produced an after-tax gain of approximately $1.6 billion, after recognizing commitments associated with certain coal contracts of $350 million, employee-related costs of $112 million and contributing to the environmental trust. The coal contract costs include the amortization of the remaining balance of ComEd's regulatory asset for unrecovered coal reserves of $178 million and the recognition of $172 million of settlement payments related to the above-market portion of coal purchase commitments ComEd assigned to EME at market value upon completion of the fossil plant sale. The severance costs included pension and postretirement welfare benefit curtailment and special termination benefit costs of $51 million and transition, separation and retention payments of $61 million. A total of 1,730 fossil station employee positions were eliminated upon completion of the fossil plant sale on December 15, 1999. The employees whose positions were eliminated have been terminated. Consistent with the provisions of Illinois legislation, the pre-tax gain on the sale of $2,587 million resulted in a regulatory liability, which was used to recover regulatory assets. Therefore, the gain on the sale, excluding $43 million of amortization of investment tax credits, was recorded as a regulatory liability in the amount of $2,544 million and amortized in the fourth quarter of 1999. The amortization of the regulatory liability and additional regulatory asset amortization of $2,456 million are reflected in depreciation and amortization expense on ComEd's Consolidated Statements of Income. 101 5. Regulatory Issues In 2001, the phased process to implement competition into the electric industry continued as mandated by the requirements of Illinois legislation. Customer Choice As of December 31, 2000, all non-residential customers were eligible to choose a new electric supplier or elect the power purchase option which allows the purchase of electric energy from ComEd at market-based prices. ComEd's residential customers become eligible to choose a new electric supplier in May 2002. As of December 31, 2001, approximately 18,700 non-residential customers, representing approximately 22% of ComEd's annual retail kilowatt-hour sales, had elected to receive their electric energy from an alternative electric supplier or had chosen the power purchase option. Customers who receive energy from an alternative supplier continue to pay a delivery charge. ComEd is unable to predict the long-term impact of customer choice on results of operations. Rate Reductions and Return on Common Equity Threshold The Illinois legislation provided a 15% residential base rate reduction effective August 1, 1998 with an additional 5% residential base rate reduction effective October 1, 2001. ComEd's operating revenues were reduced by $24 million in 2001 due to the 5% residential rate reduction. Notwithstanding the rate reductions and subject to certain earnings tests, a rate freeze will generally be in effect until at least January 1, 2005. A utility may request a rate increase during the rate freeze period only when necessary to ensure the utility's financial viability. Under the Illinois legislation, if the earned return on common equity of a utility during this period exceeds an established threshold, one-half of the excess earnings must be refunded to customers. The threshold rate of return on common equity is based on the 30-Year Treasury Bond rate plus 8.5% in the years 2000 through 2004. Earnings for purposes of ComEd's threshold include ComEd's net income calculated in accordance with GAAP and reflect the amortization of regulatory assets and goodwill. As a result of Illinois legislation, at December 31, 2001, ComEd had a regulatory asset with an unamortized balance of $277 million that it expects to fully recover and amortize by the end of 2004. Consistent with the provisions of the Illinois legislation, regulatory assets may be recovered at amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold. The utility's earned return on common equity and the threshold return on common equity for ComEd are each calculated on a two-year average basis. ComEd did not trigger the earnings sharing provision in 2000 or 2001 and does not currently expect to trigger the earnings sharing provisions in the years 2002 through 2004. Nuclear Decommissioning Costs In December 2000, the ICC issued an order, effective upon the transfer of the nuclear plants to Generation (see Note 2 - Corporate Restructuring), authorizing ComEd to recover $73 million annually from customers during the first four years of the six-year term of the PPA between ComEd and Generation. Up to $73 million annually can also be collected in 2005 and 2006, depending on the portion of the output of the former ComEd nuclear stations that ComEd purchases from Generation. Under the ICC order, subsequent to 2006, there would be no further collection for decommissioning costs from customers. All amounts collected from customers must be remitted to Generation for deposit into the related decommissioning trust funds. The ICC order also provides that any surplus trust funds after ComEd's former nuclear stations are decommissioned must be refunded to ComEd's customers. The ICC order has been appealed to the Illinois Appellate Court by ComEd and other parties. The $73 million annual recovery of decommissioning costs authorized by the ICC order represents a reduction from the $84 million annual recovery in 2000. Accordingly, in the first quarter of 2001, ComEd reduced its nuclear decommissioning regulatory asset to $372 million, reflecting the expected probable future recoveries from customers. The reduction in the 102 regulatory asset in the amount of $347 million was recorded as an adjustment to the Merger purchase price allocation and resulted in a corresponding increase in goodwill. Effective January 1, 2001, ComEd recorded an obligation to Generation of approximately $440 million representing ComEd's legal requirement to remit funds to Generation for the remaining regulatory asset amount of $372 million upon collection from customers, and for collections from customers prior to the establishment of external decommissioning trust funds in 1989 to be remitted to Generation for deposit into the decommissioning trusts through 2006. At December 31, 2001, the nuclear decommissioning regulatory asset had an unamortized balance of $310 million. 6. Supplemental Financial Information SUPPLEMENTAL INCOME STATEMENT INFORMATION

For the Period ----------------------------------- For the Year For the Year Ended October 20- January 1- Ended December 31, December 31, October 19, December 31, 2001 2000 | 2000 1999 ------------ ------------- | ------------- ------------ | | TAXES OTHER THAN INCOME | Utility $203 $52 | $224 $288 Real estate 33 22 | 101 114 Payroll 28 12 | 57 70 Other 32 (3) | 43 35 ---- --- | ---- ---- Total $296 $83 | $425 $507 ==== === | ==== ====

The decrease in taxes other than income from the prior year was primarily due to the corporate restructuring in which ComEd's nuclear generating stations were transferred to Generation (see Note 2 - Corporate Restructuring) and a change in presentation of certain revenue taxes which did not affect income.

For the Period ----------------------------------- For the Year For the Year Ended October 20- January 1- Ended December 31, December 31, October 19, December 31, 2001 2000 | 2000 1999 ------------ ------------- | ------------- ------------ | | OTHER, NET | Investment income $18 $ 9 | $ 39 $ 52 Gain (loss) on forward share | repurchase -- -- | 113 (44) Gain (loss) on disposition of | assets, net -- -- | (31) 13 AFUDC, equity and borrowed 17 -- | 19 22 Other income (expense) -- (7) | (13) 9 --- --- | ---- ---- Total $35 $ 2 | $127 $ 52 === === | ==== ====

103 SUPPLEMENTAL CASH FLOW INFORMATION

For the Period ----------------------------------- For the Year For the Year Ended October 20- January 1- Ended December 31, December 31, October 19, December 31, 2001 2000 | 2000 1999 ------------ ------------- | ------------- ------------ | Cash paid during the year: | | Interest (net of amount capitalized) $451 $ 88 | $ 418 $588 Income taxes (net of refunds) $300 $ 11 | $1,190 $485 Noncash investing and financing: | Capital lease obligations | incurred -- -- | -- $ 2 Common stock repurchase -- $850 | -- -- Settlement of forward share | Repurchase arrangement -- -- | $ 993 -- Deferred tax on fossil plant sale -- -- | $1,094 -- Net assets transferred as a | result of the restructuring, | net of note payable $1,368 -- | -- -- Contribution of receivable from | parent $1,062 -- | -- -- Purchase accounting estimate | adjustments $ (85) -- | -- -- Regulatory asset fair value | adjustment $ 347 -- | -- -- Retirement of treasury shares $2,023 -- | -- -- | Depreciation and amortization: | Property, plant and equipment $369 $ 82 | $ 543 $706 Nuclear fuel -- 44 | 144 66 Regulatory assets 170 9 | 257 46 Decommissioning -- 16 | 68 84 Goodwill 126 23 | -- --- ---- ---- | ------ ---- Total Depreciation and amortization $665 $174 | $1,012 $902 ==== ==== | ====== ====

SUPPLEMENTAL BALANCE SHEET INFORMATION REGULATORY ASSETS

at December 31, --------------- 2001 2000 ---- ---- Nuclear decommissioning costs for retired plants $ 310 $ 719 Recoverable transition costs 277 385 Loss on reacquired debt 54 35 Recoverable deferred income taxes (see Note 11) 26 (29) ------- ------- Total $ 667 $ 1,110 ======= =======

See Note 5 - Regulatory Issues - regarding the decrease in nuclear decommissioning costs for retired plants from the prior year. 104 7. Accounts Receivable Accounts receivable - Customer at December 31, 2001 and 2000 included unbilled operating revenues of $261 million and $318 million, respectively. The allowance for uncollectible accounts at December 31, 2001 and 2000 was $49 million and $60 million, respectively. 8. Property, Plant and Equipment A summary of property, plant and equipment by classification as of December 31, 2001 and 2000 is as follows:

2001 2000 ---- ---- Electric -- Transmission & Distribution $6,098 $5,612 Electric -- Generation -- 1,957 Nuclear Fuel -- 677 Construction Work in Progress 547 683 Plant Held for Future Use 46 50 Other Property, Plant and Equipment 896 912 ------ ------ Total Property, Plant and Equipment $7,587 $9,891 Less Accumulated Depreciation 236 2,234 ------ ------ Property, Plant and Equipment, net $7,351 $7,657 ====== ======

Accumulated depreciation as of December 31, 2000 includes accumulated amortization of nuclear fuel $52 million, and the nuclear decommissioning liability for the nuclear operating units of $2.1 billion which were transferred to Generation as part of the corporate restructuring. The decrease in the net property, plant and equipment balance from the prior year was primarily due to the corporate restructuring in which ComEd's nuclear generating stations were transferred to Generation (see Note 2 - Corporate Restructuring). 9. Notes Payable

2001 2000 1999 ---- ---- ---- Average borrowings -- $ 214 $ 7 Average interest rates, computed on daily basis -- 6.56% 7.75% Maximum borrowings outstanding -- $ 494 $ 8 Average interest rates, at December 31 -- -- 8.33% ---- ---- ----

Along with Exelon, PECO, and Generation, ComEd, is a party to a $1.5 billion 364-day unsecured revolving credit facility on December 12, 2001 with a group of banks. ComEd has a $300 million sublimit under this credit facility, which is used principally to support ComEd's commercial paper program. There was no outstanding debt under this credit facility or commercial paper at December 31, 2001. Interest rates on borrowings under this credit facility are based on the London Interbank Offering Rate as of the date of the advance. 105 10. Long-Term Debt

at December 31, 2001 at December 31, -------------------- --------------- Maturity Rates Date 2001 2000 ----- ---- ---- ---- ComEd Transitional Trust Notes Series 1998-A: 5.34%-5.74% 2002-2008 $ 2,380 $ 2,720 First and Refunding Mortgage Bonds (a) (b): Fixed rates 4.40%-9.875% 2002-2023 2,916 3,112 Notes payable 6.40%-9.20% 2002-2018 1,366 1,366 Pollution control bonds: Fixed rates 5.875% 2007 44 46 Floating rates 2.59% 2009-2014 92 92 Sinking fund debentures 3.125%-4.75% 2004-2011 23 27 ------------ --------- -------- -------- Total Long-Term Debt (c) 6,821 7,363 Unamortized debt discount and premium, net (122) (133) Due within one year (849) (348) -------- -------- Long-Term Debt $ 5,850 $ 6,882 ======== ========

(a) Utility plant of ComEd is subject to the liens of its mortgage indenture. (b) Includes pollution control bonds secured by first mortgage bonds issued under ComEd's mortgage indenture. (c) Long-term debt maturities in the period 2002 through 2006 and thereafter are as follows: 2002 $ 849 2003 697 2004 579 2005 806 2006 770 Thereafter 3,120 ------- Total $ 6,821 ======= In 2001, ComEd entered into forward-starting interest rate swaps, with an aggregate notional amount of $250 million, to manage interest rate exposure associated with the anticipated $400 million refinancing of ComEd First Mortgage Bonds in the first quarter of 2002. ComEd also entered into an interest rate swap agreement with a notional amount of $235 million to effectively convert fixed rate debt to floating rate debt. Prepayment premiums of $39 million, offset by unamortized issuance premiums of $17 million, associated with the early retirement of debt in 2001, have been deferred and recorded as regulatory assets and will be amortized to interest expense over the life of the related new debt issuance consistent with regulatory recovery. In 2000 and 1999, ComEd incurred extraordinary charges aggregating $6 million ($4 million, net of tax), and $46 million ($28 million, net of tax), respectively, consisting of prepayment premiums and the write-offs of unamortized deferred financing costs associated with the early retirement of debt. 106 11. Income Taxes Income tax expense (benefit) is comprised of the following components:

For the Period -------------- For the Year For the Year Ended Oct. 20- Jan. 1- Ended December 31, Dec. 31, Oct. 19, December 31, 2001 2000 2000 1999 ---- ---- ---- ---- | Included in operations: | Federal | | Current $400 $24 | $(520) $1,466 Deferred 16 57 | 729 (1,135) Investment tax credit, net (4) -- | (25) (78) State | Current 92 7 | (112) 316 Deferred 2 15 | 157 (243) ---- ---- | ---- ---- $506 $103 | $229 $326 ==== ==== | ==== ==== Included in extraordinary items: | Federal | | Current $ -- $ -- | $(2) $(15) State | ---- ---- | ---- ---- Current -- -- | -- (3) ---- ---- | ---- ---- $ -- $ -- | $(2) $(18) ==== ==== | ==== ====

The effective tax rate varies from the U.S. federal statutory rate for the years ended December 31 principally due to the following:

For the Period -------------- For the Year For the Year Ended Oct. 20- Jan. 1- Ended December 31, Dec. 31, Oct. 19, December 31, 2001 2000 2000 1999 ---- ---- | ---- ---- | | | U.S. Federal statutory rate 35.0% 35.0% | 35.0% 35.0% Increase (decrease) due to: | Plant basis differences 0.3 (1.7) | (3.7) (2.2) State income taxes, net of | Federal Income Tax | benefit 5.5 5.9 | 3.6 4.9 Amortization of goodwill 4.0 3.4 | -- -- Amortization of investment tax | credit (0.4) -- | (2.3) (5.0) Amortization of regulatory asset 1.4 -- | -- -- Unrealized loss (gain) on forward | share, repurchase arrangement -- -- | (4.8) 1.5 Other, net (0.3) 1.0 | (0.3) (0.8) ---- ---- | ---- ---- Effective income tax rate 45.5% 43.6% | 27.5% 33.4% ==== ==== | ==== ====

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

2001 2000 ---- ---- Deferred tax liabilities: Plant basis difference $ 1,149 $ 1,638 Deferred investment tax credit 55 59 Deferred debt refinancing costs 13 14 Deferred gain on like-kind exchange 453 466 Other, net 123 -- ------- -------- Total deferred tax liabilities 1,793 2,177 ------- -------- Deferred tax assets: Deferred pension and postretirement obligations (119) (250) Other, net -- (120) ------- -------- Total deferred tax assets (119) (370) ------- -------- Deferred income taxes (net) on the balance sheet $ 1,674 $ 1,807 ======= ========

In accordance with regulatory treatment of certain temporary differences, ComEd has recorded a regulatory asset/(liability) for recoverable deferred income taxes of $26 million and $(29) million at December 31, 2001 and 2000, respectively. These recoverable deferred income taxes include the deferred tax effects associated principally with liberalized depreciation accounted for in accordance with the ratemaking policies of the ICC, as well as the revenue impacts thereon, and assume continued recovery of these costs in future rates. The Internal Revenue Service is currently auditing ComEd's Federal tax returns for 1996 through 1999. The current audits are not expected to have an adverse impact on the financial condition or results of operations of ComEd. 12. Retirement Benefits ComEd has adopted defined benefit pension plans and postretirement welfare benefit plans sponsored by Exelon. Essentially all ComEd employees are eligible to participate in these plans. In 2001, ComEd's former plans were consolidated into the Exelon plans. Essentially all ComEd management employees, and electing union employees, hired on or after January 1, 2001 are eligible to participate in newly established Exelon cash balance pension plan. Management employees who were active participants in the former ComEd pension plans on December 31, 2000 and remain employed by ComEd on January 1, 2002, will have the opportunity to continue to participate in the pension plan or to transfer to the cash balance plan. Benefits under these pension plans generally reflect each employee's compensation, years of service, and age at retirement. Funding is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes and the minimum contribution required under the Employee Retirement Income Security Act of 1974, as amended. The following tables provide a reconciliation of benefit obligations, plan assets, and funded status for ComEd's proportionate allocated interest in the plans. 108

Pension Benefits Other Postretirement Benefits ---------------- ----------------------------- 2001 2000 2001 2000 ---- ---- ---- ---- Change in Benefit Obligation: Net benefit obligation at beginning of year 4,460 $ 4,119 $ 1,354 $ 1,169 Corporate restructuring (2,240) -- (815) -- Service cost 38 70 13 33 Interest cost 219 310 40 88 Plan participants' contributions -- -- 1 -- Plan amendments -- -- (76) -- Actuarial (gain)loss 116 91 (11) 76 Special accounting costs -- 125 -- 42 Gross benefits paid (145) (255) (31) (54) -------- ------- --------- -------- Net benefit obligation at end of year $ 2,448 $ 4,460 $ 475 $ 1,354 ======== ======= ========= ======== Change in Plan Assets: Fair value of plan assets at beginning of year $ 3,992 $ 4,266 $ 925 $ 949 Corporate restructuring (2,006) -- (574) -- Actual return on plan assets (68) (24) (3) (2) Employer contributions 9 5 15 32 Plan participants' contributions -- -- 1 4 Gross benefits paid (145) (255) (31) (58) -------- ------- --------- -------- Fair value of plan assets at end of year $ 1,782 $ 3,992 $ 333 $ 925 ======== ======= ========= ======== Funded status at end of year $ (666) $ (468) $ (142) $ (429) Miscellaneous adjustment -- -- -- 6 Unrecognized net actuarial (gain)loss 515 183 72 108 Unrecognized prior service cost -- -- (76) -- -------- ------- --------- -------- Net amount recognized at end of year $ (151) $ (285) $ (146) $ (315) ======== ======= ========= ========

Pension Benefits Other Postretirement Benefits -------------------------------- ------------------------------------- 2001 2000 1999 2001 2000 1999 ---- ---- ---- ---- ---- ---- WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31, Discount rate 7.35% 7.60% 6.75% 7.35% 7.60% 6.75% Expected return on plan assets 9.50% 9.50% 9.25% 9.50% 9.22% 8.97% Rate of compensation increase 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% Health care cost trend on covered charges N/A N/A N/A 10.00% 7.00% 8.00% decreasing decreasing decreasing to ultimate to ultimate to ultimate trend of 4.5% trend of 5.0% trend of 5.0% in 2008 in 2005 in 2005

109

Pension Benefits Other Postretirement Benefits ---------------------- ----------------------- 2001 2000 1999 2001 2000 1999 ---- ---- ---- ---- ---- ---- COMPONENTS OF NET PERIODIC BENEFIT COST (BENEFIT): Service cost $ 38 $ 70 $ 120 $ 13 $ 33 $ 41 Interest cost 219 310 285 40 88 82 Expected return on assets (246) (394) (362) (36) (85) (76) Amortization of: Transition obligation (asset) -- (9) (13) -- 16 22 Prior service cost -- (1) (4) (4) 3 4 Actuarial (gain) loss -- (5) 3 1 (17) (14) Curtailment charge (credit) -- -- 16 -- -- 35 Settlement charge (credit) -- -- -- -- -- 1 ----- ------ ------ -------- ------ ----- Net periodic benefit cost (benefit) $ 11 $ (29) $ 45 $ 14 $ 38 $ 95 ===== ====== ====== ======== ====== ===== Special accounting costs $ -- $ 4 $ -- $ -- $ 5 $ -- ===== ====== ====== ======== ====== =====

SENSITIVITY OF RETIREE WELFARE RESULTS Effect of a one percentage point increase in assumed health care cost trend on total service and interest cost components $ 10 on postretirement benefit obligation $ 60 Effect of a one percentage point decrease in assumed health care cost trend on total service and interest cost components $ (8) on postretirement benefit obligation $ (54) The decrease in the net benefit obligation and the fair value of plan assets from the prior year is due primarily to the corporate restructuring (see Note 2 - Corporate Restructuring). Amounts of the obligation allocated to affiliates in the restructuring were primarily based on the relative number of active employees transferred to each affiliate. Prior service cost is amortized on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans. Special accounting costs in 2000 of $125 million represent ComEd's accelerated liability increase, including $100 million for separation benefits and $25 million for plan enhancements. ComEd provides certain health care and life insurance benefits for retired employees through plans sponsored by Exelon. In 2001, to more closely align the benefit plans of ComEd and PECO, Exelon amended the former ComEd postretirement medical benefit plan that changed the eligibility requirement of the plan to cover only employees who retire with 10 years of service after age 45 rather than with 10 years of service and having attained the age of 55. Welfare benefits for active employees are provided by several insurance policies or self-funded plans whose premiums or contributions are based upon the benefits paid during the year. Additionally, ComEd provides nonqualified supplemental retirement plans which cover any excess pension benefits that would be payable to management employees under the qualified plan but which are limited by the Internal Revenue Code. The fair value of plan assets excludes $23 million held in a trust as of December 31, 2001 for the payment of benefits under the supplemental plans and $8 million held in a trust as of December 31, 2001 for the payment of postretirement medical benefits. ComEd has savings plans for the majority of its employees. The plans allow employees to contribute a portion of their pretax income in accordance with specified guidelines. ComEd matches a percentage of the employee contribution up to certain limits. The cost of ComEd's matching contribution to the savings plans totaled $20 million, $31 million, and $32 million in 2001, 2000 and 1999, respectively. 110 13. Preferred Securities PREFERRED AND PREFERENCE STOCK At December 31, 2000, there were 51,773 authorized shares of $1.425 convertible preferred stock. At December 31, 2001 and 2000, there were 6,810,451 authorized shares of preference stock and 850,000 authorized shares of prior preferred stock.

at December 31, Shares Outstanding Dollar Amount ------------------ ------------- 2001 2000 1999 2001 2000 1999 ---- ---- ---- ---- ---- ---- WITHOUT MANDATORY REDEMPTION $1.425 convertible preferred stock, cumulative, without par value -- -- 56,291 $ -- $ -- $ 2 Preference stock, non-cumulative, without par value 1,120 1,120 1,120 7 7 7 ----- ----- ------ ----- ---- ------ Total preferred and preference stock 1,120 1,120 57,411 $ 7 $ 7 $ 9 ===== ===== ====== ===== ==== ======

Preferred and preference stock redemptions were 56,291 and 13,502,949 shares in 2000 and 1999, respectively. COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY THE COMPANY'S SUBORDINATED DEBT SECURITIES At December 31, 2001 and 2000, subsidiary trusts of ComEd had outstanding the following securities:

Mandatory at December 31, --------- --------------- Redemption Distribution Liquidation Trust Receipts Outstanding Dollar Amount ---------- ------------ ----------- -------------------------- ------------- Series Date Rate Value 2001 2000 2001 2000 ------ ---- ---- ----- ---- ---- ---- ---- ComEd Financing I 2035 8.48% $ 25 8,000,000 8,000,000 $ 200 $200 ComEd Financing II 2027 8.50% 1,000 150,000 150,000 150 150 Unamortized Discount -- -- (21) (22) --------- --------- ----- ---- Total 8,150,000 8,150,000 $ 329 $328 ========= ========= ===== ====

ComEd Financing I and ComEd Financing II are wholly owned subsidiary trusts of ComEd. The sole assets of each ComEd trust are subordinated deferrable interest debt securities issued by ComEd bearing interest rates equivalent to the distribution rate of the related trust security. The interest expense on the deferrable interest debt securities is included in Distributions on Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely the Company's Subordinated Debt Securities in ComEd's Consolidated Statements of Income and is deductible for income tax purposes. 14. Common Stock At December 31, 2001 and 2000, common stock with a $12.50 par value consisted of 250,000,000 and 250,000,000 shares authorized and 127,016,000 and 163,805,000 shares outstanding, respectively. During the second quarter of 2001, ComEd canceled 50.4 million of its common shares totaling $2.023 million. At December 31, 2001 and 2000, 67,317 and 74,988, respectively, of ComEd common stock purchase warrants were outstanding. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants. At December 31, 2001, 22,439 shares of common stock were reserved for the conversion of warrants. 111 FORWARD PURCHASE AGREEMENTS In the fourth quarter of 1998, ComEd entered into a forward purchase arrangement with Unicom for the repurchase of $200 million of ComEd common stock. This contract, which was accounted for as an equity instrument as of December 31, 1999, was settled on a net cash basis in February 1999, resulting in a $16 million reduction to Common Stock equity on ComEd's Consolidated Balance Sheets. In January 2000, ComEd physically settled the forward share repurchase arrangements it had with Unicom for the repurchase of 26.3 million ComEd common shares. Prior to settlement, the repurchase arrangements were recorded as a receivable on ComEd's Consolidated Balance Sheets based on the aggregate market value of the shares under the arrangements. In 1999, net unrealized losses of $44 million (after-tax) were recorded related to the arrangements. The settlement of the arrangements in January 2000 resulted in a gain of $113 million (after-tax), which was recorded in the first quarter of 2000. The settlement of the arrangements resulted in a reduction in ComEd's outstanding common shares and common stock equity, effective January 2000. STOCK REPURCHASES During the first quarter of 2000, ComEd repurchased four million of its common shares from Unicom for $153 million using proceeds from the 1998 issuance of transitional trust notes. In the fourth quarter of 2000, ComEd repurchased 19.9 million of its common shares from Unicom in exchange for an $850 million note receivable ComEd held from Unicom Investment. As part of the restructuring, ComEd received 36.8 million of its common shares from Exelon totaling $1,344 million in exchange for the net assets transferred to Generation and notes payable received from Generation. SHARES OUTSTANDING The following table details ComEd's common stock and treasury stock:

Common Treasury (in thousands) Shares Shares -------------- ------ ------ Balance, December 31, 1998 214,236 179 Conversion of $1.425 Preferred Stock 2 -- Common Stock Repurchases -- 85 ------- ------ Balance, December 31, 1999 214,238 264 Conversion of $1.425 Preferred Stock 4 -- Common Stock Repurchases -- 3,964 Stock Forward Repurchase Contract -- 26,268 ------- ------ Balance, October 19, 2000 214,242 30,496 Common Stock Repurchases -- 19,941 ------- ------ Balance, December 31, 2000 214,242 50,437 Retirement of Treasury Shares (50,437) (50,437) Restructuring (see Note 2 - Corporate Restructuring) -- 36,789 ------- ------ Balance, December 31, 2001 163,805 36,789 ======= ======

112 15. Fair Value of Financial Assets and Liabilities The carrying amounts and fair values of ComEd's financial instruments as of December 31, 2001 and 2000 were as follows:

2001 2000 ---- ---- Carrying Carrying Amount Fair Value Amount Fair Value ------ ---------- ------ ---------- NON-DERIVATIVES: Liabilities Long-term debt (including amounts due within one year) $ 6,699 $ 7,088 $ 7,230 $ 7,455 Company-Obligated Mandatorily Redeemable Preferred Securities $ 329 $ 394 $ 328 $ 347 DERIVATIVES: Energy derivatives -- -- (34) (34) Forward interest rate swaps (1) (1) -- -- --------- -------- -------- ---------

Cash and cash equivalents, customer accounts receivable, and trust accounts for decommissioning nuclear plants are recorded at their fair value. As of December 31, 2001 and 2000, ComEd's carrying amounts of cash and cash equivalents and accounts receivable are representative of fair value because of the short-term nature of these instruments. Fair values of the trust accounts for decommissioning nuclear plants, long-term debt, and Company-Obligated Mandatorily Redeemable Preferred Securities are estimated based on quoted market prices for the same or similar issues. The fair value of ComEd's interest rate swaps and energy derivatives is determined using quoted exchange prices, external dealer prices, or internal valuation models which utilize assumptions of future energy prices and available market pricing curves. Financial instruments that potentially subject ComEd to concentrations of credit risk consist principally of cash equivalents and customer accounts receivable. ComEd places its cash equivalents with high-credit quality financial institutions. Generally, such investments are in excess of the Federal Deposit Insurance Corporation limits. Concentrations of credit risk with respect to customer accounts receivable are limited due to ComEd's large number of customers and their dispersion across many industries. ComEd has entered into forward-starting interest rate swaps to manage interest rate exposure in the aggregate notional amount of $250 million. These swaps have been designated as cash-flow hedges under SFAS 133, and as such, as long as the hedge remains effective, and the underlying transaction remains probable, changes in the fair value of these swaps will be recorded in accumulated other comprehensive income (loss) until earnings are affected by the variability of the cash flows being hedged. ComEd has also entered into an interest rate swap to effectively convert $235 million in fixed-rate debt to a floating rate debt. This swap has been designated as a fair-value hedge, as defined in SFAS No. 133 and as such, changes in the fair value of the swap will be recorded in earnings. However, as long as the hedge remains effective and the underlying transaction remains probable, changes in the fair value of the swap will be offset by changes in the fair value of the hedged liabilities. Any change in the fair value of the hedge as a result of ineffectiveness would be recorded immediately in earnings. The notional amount of derivatives do not represent amounts that are exchanged by the parties and, thus, are not a measure of ComEd's exposure. The amounts exchanged are calculated on the basis of the notional or contract amounts, as well as on the other terms of the derivatives, which relate to interest rates and the volatility of these rates. 113 ComEd would be exposed to credit-related losses in the event of non-performance by the counterparties that issued the derivative instruments. The credit exposure of derivative contracts is represented by the fair value of contracts at the reporting date. ComEd's interest rate swaps are documented under master agreements. Among other things, these agreements provide for a maximum credit exposure for both parties. Payments are required by the appropriate party when the maximum limit is reached. The initial adoption of SFAS No.133, as amended, on January 1, 2001 had no financial statement impact on ComEd. SFAS No. 133 must be applied to all derivative instruments and requires that such instruments be recorded in the balance sheet either as an asset or a liability measured at their fair value through earnings, with special accounting permitted for certain qualifying hedges. Additionally, during 2001, no amounts were reclassified from accumulated other comprehensive income into earnings as a result of forecasted financing transactions no longer being probable. 16. Commitments and Contingencies CAPITAL COMMITMENTS ComEd estimates that it will spend approximately $781 million for capital expenditures in 2002. ENERGY COMMITMENTS In connection with the corporate restructuring (see Note 2 - Corporate Restructuring), ComEd assigned its respective rights and obligations under various power purchase and fuel supply agreements to Generation. Additionally, ComEd entered into a PPA with Generation. Under the PPA between ComEd and Generation, Generation has agreed to supply all of ComEd's load requirements through 2004. Prices for this energy vary depending upon the time of day and month of delivery. During 2005 and 2006, ComEd's PPA is a partial requirements agreement under which ComEd will purchase all of its required energy and capacity from Generation, up to the available capacity of the nuclear generating plants formerly owned by ComEd and transferred to Generation. Under the terms of the PPA, Generation is responsible for obtaining any required transmission service. The PPA also specifies that prior to 2005, ComEd and Generation will jointly determine and agree on a market-based price for energy delivered under the PPA for 2005 and 2006. In the event that the parties cannot agree to market-based prices for 2005 and 2006 prior to July 1, 2004, ComEd has the option of terminating the PPA effective December 31, 2004. ComEd will obtain any additional supply required from market sources in 2005 and 2006, and subsequent to 2006, will obtain all of its supply from market sources, which could include Generation. 114 ENVIRONMENTAL ISSUES ComEd's operations have in the past and may in the future require substantial capital expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, ComEd is generally liable for the costs of remediating environmental contamination of property now or formerly owned by ComEd and of property contaminated by hazardous substances generated by ComEd. ComEd owns a number of real estate parcels, including parcels on which its operations or the operations of others may have resulted in contamination by substances which are considered hazardous under environmental laws. ComEd has identified 44 sites where former manufactured gas plant (MGP) activities have or may have resulted in actual site contamination. ComEd is currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. As of December 31, 2001 and 2000, ComEd had accrued $105 million and $117 million, respectively, for environmental investigation and remediation costs, including $100 million and $110 million, respectively, (reflecting discount rates of 5.5%) for MGP investigation and remediation, that currently can be reasonably estimated. Such estimates, reflecting the effects of a 3% inflation rate before the effects of discounting were $154 million and $170 million at December 31, 2001 and 2000, respectively. ComEd anticipates that payments related to the discounted environmental investigation and remediation costs, recorded on an undiscounted basis of $68 million, will be incurred for the five year period through 2006. ComEd cannot reasonably estimate whether it will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by ComEd, environmental agencies or others, or whether such costs will be recoverable from third parties. LEASES Minimum future operating lease payments, including lease payments for real estate and vehicles, as of December 31, 2001 were: 2002 $ 28 2003 27 2004 24 2005 20 2006 19 Remaining years 68 ------- Total minimum future lease payments $ 186 ======= Rental expense under operating leases totaled $23 million, $30 million, and $45 million in 2001, 2000 and 1999, respectively. LITIGATION Chicago Franchise. In March 1999, ComEd reached a settlement agreement with the City of Chicago to end the arbitration proceeding between ComEd and Chicago regarding the January 1, 1992 franchise agreement. As part of the settlement agreement, ComEd and Chicago agreed to a revised combination of ongoing work under the franchise agreement and new initiatives that total approximately $1 billion in defined transmission and distribution expenditures by ComEd to improve electric services in Chicago, of which approximately $940 million has been expended through December 31, 2001. The settlement agreement provides that ComEd would be subject to liquidated damages if the projects are not completed by various dates, unless it was prevented from doing so by events beyond its reasonable control. In addition, ComEd and Chicago established an Energy Reliability and Capacity Account, into which ComEd deposited $25 million during each of the years 1999 through 2001 and has conditionally agreed to deposit $25 million at the end of 2002, to help ensure an adequate and reliable electric supply for Chicago. 115 FERC Municipal Request for Refund. Three of ComEd's wholesale municipal customers filed a complaint and request for refund with the FERC alleging that ComEd failed to properly adjust its rates, as provided for under the terms of the electric service contracts with the municipal customers and to track certain refunds made to ComEd's retail customers in the years 1992 through 1994. In the third quarter of 1998, FERC granted the complaint and directed that refunds be made, with interest. ComEd filed a request for rehearing. On April 30, 2001, FERC issued an order granting rehearing in which it determined that its 1998 order had been erroneous and that no refunds were due from ComEd to the municipal customers. On June 29, 2001, FERC denied the customers' requests for rehearing of the order granting rehearing. In August 2001, each of the three wholesale municipal customers appealed the April 30, 2001 FERC order to the Federal circuit court, which consolidated the appeals for the purposes of briefing and decision. In November 2001, the court suspended briefing pending court-initiated settlement discussions. Godley Park District Litigation. On April 18, 2001, the Godley Park District filed suit in Will County Circuit Court against ComEd and Exelon alleging that oil spills at Braidwood Station have contaminated the Park District's water supply. The complaint sought actual damages, punitive damages of $100 million and statutory penalties. The court dismissed all counts seeking punitive damages and statutory penalties, and the plaintiff has filed an amended complaint after the court. ComEd is contesting the liability and damages sought by the plaintiff. Retail Rate Law. In 1996, several developers of non-utility generating facilities filed litigation against various Illinois officials claiming that the enforcement against those facilities of an amendment to Illinois law removing the entitlement of those facilities to state-subsidized payments for electricity sold to ComEd after March 15, 1996 violated their rights under the Federal and State of Illinois constitutions. The developers also filed suit against ComEd for a declaratory judgement that their rights under their contracts with ComEd were not affected by the amendment. On August 4, 1999, the Illinois Appellate Court held that the developers' claims against the state were premature, and the Illinois Supreme Court denied leave to appeal that ruling. Developers of both facilities have since filed amended complaints repeating their allegations that ComEd breached the contracts in question and requesting damages for such breach, in the amount of the difference between the state-subsidized rate and the amount ComEd was willing to pay for the electricity. ComEd is contesting this matter. Service Interruptions. In August 1999, three class action lawsuits were filed against ComEd, and subsequently consolidated, in the Circuit Court of Cook County, Illinois seeking damages for personal injuries, property damage and economic losses related to a series of service interruptions that occurred in the summer of 1999. The combined effect of these interruptions resulted in over 168,000 customers losing service for more than four hours. Conditional class certification was approved by the court for the sole purpose of exploring settlement talks. ComEd filed a motion to dismiss the complaints. On April 24, 2001, the court dismissed four of the five counts of the consolidated complaint without prejudice and the sole remaining count was dismissed in part. On June 1, 2001, the plaintiffs filed a second amended consolidated complaint and ComEd has filed an answer. A portion of any settlement or verdict may be covered by insurance; discussions with the carrier are ongoing. ComEd's management believes adequate reserves have been established in connection with these cases. Enron. As a result of Enron Corp.'s bankruptcy proceeding, ComEd has potential monetary exposure for customers served by Enron Energy Services (EES) as a billing agent. On January 7, 2002, EES was authorized by the bankruptcy court to, and subsequently did, reject its contract with 129 of ComEd's customer accounts. As of March 15, 2002, EES was the billing agent for 97 of ComEd's customer accounts. EES has advised Exelon that it will retain its billing 116 agency with these remaining accounts. ComEd is working to ensure that customers know what amounts are owed to ComEd on 269 accounts on which EES has been removed as billing agent, and has obtained updated billing addresses for these accounts. With regard to the 97 remaining accounts, as of March 15, 2002, ComEd's total amount outstanding is immaterial. Because that amount is owed to ComEd by individual customers, it is not part of the bankrupt Enron's estate. The ICC has rescinded EES's authority to act as an alternative retail energy supplier in Illinois. However, EES never served as a supplier, as opposed to a billing agent, to any of ComEd's retail accounts. General. ComEd is involved in various other litigation matters. The ultimate outcome of such matters, while uncertain, is not expected to have a material adverse effect on its respective financial condition or results of operations. 17. Related-Party Transactions At December 31, 2000, ComEd had a $400 million receivable from PECO, which was repaid in the second quarter of 2001. The average interest rate on this receivable for the period outstanding was 6.5%. Interest income on the receivable from PECO was $8 million for the year ended December 31, 2001. ComEd had a $1.3 billion note receivable from Unicom Investment Inc. at December 31, 2001 and December 31, 2000, relating to the December 1999 fossil plant sale, which is included in Deferred Debits and Other Assets in ComEd's Consolidated Balance Sheets. Interest income earned on this note receivable was $61 million and $176 million for the years ended December 31, 2001 and 2000. Interest receivable due on this note was $24 million and $38 million at December 31, 2001 and December 31, 2000, respectively, and was included in Current Assets on ComEd's Consolidated Balance Sheets. At December 31, 2001, ComEd had a $937 million non-interest bearing receivable from Exelon relating to Exelon's agreement to fund future income tax payments resulting from the collection by ComEd of instrument funding charges. This receivable is reflected as a reduction of Shareholders' Equity in ComEd's Consolidated Balance Sheets and is expected to be settled over the years 2002 through 2008. At December 31, 2001, ComEd had a short-term payable of $59 million and a long-term payable of $290 million to Generation primarily representing ComEd's legal requirement to remit collections of nuclear decommissioning costs from customers to Generation resulting from the restructuring (see Note 5 - Regulatory Issues). These liabilities to Generation were included in Current Liabilities and Deferred Credits and Other Liabilities, respectively, on ComEd's Consolidated Balance Sheets. In consideration for the net assets transferred as part of the restructuring (see Note 2 - Corporate Restructuring), ComEd had a note payable to affiliates of $450 million. This note payable was repaid during 2001. Interest expense paid on the outstanding balance of the note payable, excluding the portion related to the nuclear decommissioning liability discussed above, was $10 million for the year ended December 31, 2001. ComEd paid common stock dividends to Exelon of $483 million in 2001. In connection with the transfer of the generating assets in the corporate restructuring, ComEd entered into a PPA with Generation. See Note 2 - Corporate Restructuring. Intercompany power purchases pursuant to the PPA for the year ended December 31, 2001 were $2,656 million. At December 31, 2001, there was a $183 million payable to Generation for the PPA as well as other services provided which is included in Current Liabilities on ComEd's Consolidated Balance Sheets. ComEd provides electric, transmission and other ancillary services to Generation and Enterprises. These services were recorded in revenues and were $81 million and $90 million for 117 the years ended December 31, 2001 and 2000, respectively. At December 31, 2001, there was a $26 million receivable from Generation for services provided which is included in Current Assets on ComEd's Consolidated Balance Sheets. Effective January 1, 2001, upon the corporate restructuring, ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial and information technology services. Such services, provided at cost including applicable overhead, were $134 million for the year ended December 31, 2001, of which $128 million was included in Operating and Maintenance (O&M) expense on ComEd's Consolidated Statements of Income and $6 million was capitalized. At December 31, 2001, there was a $14 million payable to BSC for services provided which is included in Current Liabilities on ComEd's Consolidated Balance Sheets. ComEd receives transmission related services under contracts with InfraSource, Inc, formerly Exelon Infrastructure Services, Inc. Such services, totaling $26 million, were capitalized in 2001. In 2001, ComEd contracted with Unicom Mechanical Services Inc. to provide energy conservation services to ComEd customers. The costs were $20 million for the year ended December 31, 2001, and were included in O&M expense on ComEd's Consolidated Statements of Income. In order to administer payment processing, ComEd processes certain invoice payments on behalf of Generation and BSC. Receivables at December 31, 2001 from Generation and BSC for such service totaled $21 million and $19 million, respectively, and were included in Current Assets on ComEd's Consolidated Balance Sheets. Interest income earned on such outstanding receivables from Generation and BSC was $9 million and $1 million, respectively, for the year ended December 31, 2001. 18. Quarterly Data (Unaudited) The data shown below include all adjustments which ComEd considers necessary for a fair presentation of such amounts:

Operating Operating Income Before Net Revenues Income Extraordinary Items Income --------------- ------------- ------------------- -------------- Quarter ended 2001 2000 2001 2000 2001 2000 2001 2000 ------------- ---- ---- ---- ---- ---- ---- ---- ---- March 31 $1,446 $1,563 $380 $268 $146 $209 $146 $206 June 30 $1,530 $1,711 $459 $366 $182 $178 $182 $177 September 30 $1,919 $2,093 $440 $366 $178 $197 $178 $197 December 31 $1,311 $1,645 $315 $386 $101 $152 $101 $152 ------ ------ ---- ---- ---- ---- ---- ----

19. Subsequent Event On March 13, 2002, ComEd issued $400 million of 6.15% First Mortgage Bonds, due March 15, 2012. On March 21, 2002, ComEd redeemed $200 million of 8.625% First Mortgage Bonds at the redemption price of 103.84% of the principal amount plus accrued interest. These bonds had a maturity date of February 1, 2022. The $400 million bond issuance was a replacement of the $200 million bonds early retired on March 21, 2002 and the $196 million 9.875% First Mortgage Bonds which were early retired in November, 2001. 118 PECO REPORT OF INDEPENDENT ACCOUNTANTS To the Shareholders and Board of Directors of PECO Energy Company: In our opinion, the consolidated financial statements listed in the index appearing under Item 14(a)(3)(i) present fairly, in all material respects, the financial position of PECO Energy Company and Subsidiary Companies (PECO) at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 14(a)(3)(ii) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of PECO's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 2, as part of a corporate restructuring undertaken on January 1, 2001 by Exelon Corporation, the parent company of PECO, certain of PECO's operations, assets and liabilities, including those related to power generation and enterprises, were transferred to affiliated companies of PECO. As discussed in Note 5 to the consolidated financial statements, PECO changed its method of accounting for nuclear outage costs in 2000. As discussed in Note 1 to the consolidated financial statements, PECO changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001. PricewaterhouseCoopers LLP Philadelphia, Pennsylvania January 29, 2002 119 PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, -------------------------------- (in millions) 2001 2000 1999 ------------- ---- ---- ---- OPERATING REVENUES Operating Revenues $ 3,953 $ 5,950 $ 5,478 Operating Revenues from Affiliates 12 -- -- Total Operating Revenues 3,965 5,950 5,478 OPERATING EXPENSES Fuel and Purchased Power 640 2,127 2,152 Purchased Power from Affiliates 1,162 -- -- Operating and Maintenance 527 1,791 1,454 Operating and Maintenance from Affiliates 60 -- -- Merger-Related Costs -- 248 -- Depreciation and Amortization 416 325 237 Taxes Other Than Income 161 237 262 -------- ------- -------- Total Operating Expenses 2,966 4,728 4,105 -------- ------- -------- OPERATING INCOME 999 1,222 1,373 -------- ------- -------- OTHER INCOME AND DEDUCTIONS Interest Expense (405) (457) (396) Interest Expense from Affiliates (8) -- -- Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership, which holds Solely Subordinated Debentures of the Company (10) (8) (21) Equity in Earnings (Losses) of Unconsolidated Affiliates -- (41) (38) Interest Income from Affiliates 10 -- -- Other, Net 36 41 59 -------- ------- -------- Total Other Income and Deductions (377) (465) (396) -------- ------- -------- INCOME BEFORE INCOME TAXES, EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 622 757 977 INCOME TAXES 197 270 358 -------- ------- -------- INCOME BEFORE EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 425 487 619 EXTRAORDINARY ITEMS (NET OF INCOME TAXES OF $2, AND $25 FOR 2000, AND 1999, RESPECTIVELY) -- (4) (37) CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE (NET OF INCOME TAXES OF $16) -- 24 -- -------- ------- -------- NET INCOME 425 507 582 PREFERRED STOCK DIVIDENDS 10 10 12 -------- ------- -------- NET INCOME ON COMMON STOCK $ 415 $ 497 $ 570 ======== ======= ========

See Notes to Consolidated Financial Statements 120 PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, ----------------------------------- (in millions) 2001 2000 1999 ------------- ---- ---- ---- CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 425 $ 507 $ 582 Adjustments to reconcile Net Income to Net Cash Flows provided by Operating Activities: Depreciation and Amortization 416 437 358 Extraordinary Items (net of income taxes) -- 4 37 Cumulative Effect of a Change in Accounting Principle (net of income taxes) -- (24) -- Provision for Uncollectible Accounts 69 68 59 Deferred Income Taxes (66) 103 (7) Merger-Related Costs -- 248 -- Deferred Energy Costs 29 (79) 23 Equity in (Earnings) Losses of Unconsolidated Affiliates -- 41 38 Other Operating Activities 79 (76) (20) Changes in Working Capital: Accounts Receivable (54) (264) (159) Repurchase of Accounts Receivable -- (50) (150) Inventories (15) (45) (43) Accounts Payable, Accrued Expenses & Other Current Liabilities (133) (85) 189 Change in Receivables and Payables to Affiliates, net 73 -- -- Other Current Assets 5 (29) (12) ----------- ---------- --------- NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES 828 756 895 ----------- ---------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Investment in Plant (264) (549) (491) InfraSource, Inc.Acquisitions -- (245) (222) Investments in and Advances to Joint Ventures -- -- (118) Proceeds from Nuclear Decommissioning Trust Funds -- 74 69 Investment in Nuclear Decommissioning Trust Funds -- (100) (95) Other Investing Activities 29 (74) (29) ----------- ---------- --------- NET CASH FLOWS USED IN INVESTING ACTIVITIES (235) (894) (886) ----------- ---------- --------- CASH FLOWS FROM FINANCING ACTIVITIES Issuance of Long-Term Debt, net of issuance costs 1,055 1,021 4,170 Common Stock Repurchases -- (496) (1,705) Retirement of Long-Term Debt (1,416) (557) (1,343) Change in Receivable and Payable to Affiliates 25 400 -- Change in Notes Payable (60) -- (388) Redemption of COMRPS -- -- (221) Redemptions of Mandatorily Redeemable Preferred Stock (18) (19) (37) Change in Restricted Cash (69) (80) (174) Dividends on Preferred and Common Stock (352) (167) (208) Proceeds from Employee Stock Plans -- 47 19 Capital Lease Payments -- -- (139) Contribution from Parent 225 -- -- Proceeds on the Settlement of Interest Rate Swap Agreements 31 -- -- Other Financing Activities -- (16) 23 ----------- ---------- --------- NET CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES (579) 133 (3) ----------- ---------- --------- INCREASE IN CASH AND CASH EQUIVALENTS 14 (5) 6 Cash Transferred in Restructuring (31) -- -- CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 49 54 48 ----------- ---------- --------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 32 $ 49 $ 54 =========== ========== =========

See Notes to Consolidated Financial Statements 121 PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS

at December 31, --------------------- (in millions) 2001 2000 ------------- ---- ---- ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 32 $ 49 Restricted Cash 323 254 Accounts Receivable, net Customer 286 774 Other 33 250 Inventories, at average cost Fossil Fuel 72 135 Materials and Supplies 7 122 Receivable from Affiliates 8 -- Other 59 195 ------- -------- Total Current Assets 820 1,779 ------- -------- PROPERTY, PLANT AND EQUIPMENT, NET 4,047 5,158 DEFERRED DEBITS AND OTHER ASSETS Regulatory Assets 5,756 6,026 Nuclear Decommissioning Trust Funds -- 440 Investments 24 847 Goodwill, net -- 326 Pension Asset 13 -- Other 85 200 ------- -------- Total Deferred Debits and Other Assets 5,878 7,839 ------- -------- TOTAL ASSETS $10,745 $ 14,776 ======= ======== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Notes Payable $ 101 $ 163 Payables to Affiliates 194 1,096 Long-Term Debt Due Within One Year 548 553 Accounts Payable 54 403 Accrued Expenses 397 637 Deferred Income Taxes 27 27 Other 21 95 ------- -------- Total Current Liabilities 1,342 2,974 ------- -------- LONG-TERM DEBT 5,438 6,002 DEFERRED CREDITS AND OTHER LIABILITIES Deferred Income Taxes 2,938 2,532 Unamortized Investment Tax Credits 27 271 Pension Obligations -- 129 Non-Pension Postretirement Benefits Obligation 239 501 Payables to Affiliates 44 -- Other 110 427 ------- -------- Total Deferred Credits and Other Liabilities 3,358 3,860 ------- -------- COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF A PARTNERSHIP, WHICH HOLDS SOLELY SUBORDINATED DEBENTURES OF THE COMPANY 128 128 MANDATORILY REDEEMABLE PREFERRED STOCK 19 37 COMMITMENTS AND CONTINGENCIES SHAREHOLDERS' EQUITY Common Stock 1,912 1,442 Receivable from Parent (1,878) -- Preferred Stock 137 137 Retained Earnings 270 197 Accumulated Other Comprehensive Income (Loss) 19 (1) ------- -------- Total Shareholders' Equity 460 1,775 ------- -------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $10,745 $ 14,776 ======= ========

See Notes to Consolidated Financial Statements 122 PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

Accumulated Receivable Other Total Common Preferred from Deferred Retained Comprehensive Treasury Shareholders' (in millions) Stock Stock Parent Compensation Earnings Income Stock Equity ------------- ----- ----- ------ ------------ -------- ------ ----- ------ BALANCE, DECEMBER 31, 1998 $ 3,558 $ 137 $ -- $ -- $ (501) $ -- $ -- $ 3,194 Net Income -- -- -- -- 582 -- -- 582 Long-Term Incentive Plan 19 -- -- (5) 15 -- -- 29 Deferred Compensation -- -- -- 2 -- -- -- 2 Common Stock Dividends -- -- -- -- (196) -- -- (196) Preferred Stock Dividends -- -- -- -- (12) -- -- (12) Common Stock Repurchases -- -- -- -- 12 -- (1,705) 1,693) Other Comprehensive Income, net of income taxes of $3 -- -- -- -- -- 4 -- 4 ------- ------- ----- ----- ------- -------- --------- ------- BALANCE, DECEMBER 31, 1999 3,577 137 -- (3) (100) 4 (1,705) 1,910 Net Income -- -- -- -- 507 -- -- 507 Long-Term Incentive Plan 47 -- -- (9) 7 -- 7 52 Deferred Compensation -- -- -- 5 -- -- -- 5 Common Stock Dividends -- -- -- -- (157) -- -- 157) Preferred Stock Dividends -- -- -- -- (10) -- -- (10) Unicom Merger Consideration -- -- -- -- (45) -- -- (45) Common Stock Repurchases -- -- -- -- (5) -- (496) (501) Stock Option Exercises -- -- -- -- -- -- 19 19 Cancellation of Treasury Shares (2,175) -- -- -- -- -- 2,175 -- Other Comprehensive Income, net of income taxes of $(3) -- -- -- -- -- (5) -- (5) Reorganization Pursuant to Share Exchange (7) -- -- 7 -- -- -- -- ------- ------- ----- ----- ------- -------- --------- ------- BALANCE, DECEMBER 31, 2000 1,442 137 -- -- 197 (1) -- 1,775 Net Income -- -- -- -- 425 -- -- 425 Common Stock Dividends -- -- -- -- (342) -- -- (342) Preferred Stock Dividends -- -- -- -- (10) -- -- (10) Receivable from Parent 1,983 -- (1,983) -- -- -- -- -- Repayment of Receivable from Parent -- -- 105 -- -- -- -- 105 Stock Option Exercises (26) -- -- -- -- -- -- (26) Capital Contribution from Parent 121 -- -- -- -- -- -- 121 Net Assets Transferred in Restructuring (1,608) -- -- -- -- -- -- (1,608) Other Comprehensive Income, net of income taxes of $16 -- -- -- -- -- 20 -- 20 ------- ------- ----- ----- ------- -------- --------- ------- BALANCE, DECEMBER 31, 2001 $ 1,912 $ 137 $(1,878) $ -- $ 270 $ 19 $ -- $ 460 ======= ======= ======= ===== ======= ====== ========= =======

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, -------------------------------- (in millions) 2001 2000 1999 ------------- ---- ---- ---- NET INCOME $ 425 $ 507 $ 582 OTHER COMPREHENSIVE INCOME SFAS 133 Transition Adjustment, net of income taxes of $29 $ 40 $ -- $ -- Cash Flow Hedge Fair Value Adjustment, net of income taxes of $(13) (20) -- -- Unrealized Gain (Loss) on Marketable Securities, net of income taxes of $(2) and $2 for 2000 and 1999, respectively -- (5) 4 -------- --------- -------- Total Other Comprehensive Income 20 (5) 4 -------- --------- -------- Total Comprehensive Income $ 445 $ 502 $ 586 ======== ========= ========

See Notes to Consolidated Financial Statements 123 PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in millions, except per share data unless otherwise noted) 1. SIGNIFICANT ACCOUNTING POLICIES DESCRIPTION OF BUSINESS Incorporated in Pennsylvania in 1929, PECO Energy Company (PECO) is engaged principally in the production, purchase, transmission, distribution and sale of electricity to residential, commercial, industrial and wholesale customers and the distribution and sale of natural gas to residential, commercial and industrial customers. Pursuant to the Pennsylvania Electricity Generation Customer Choice and Competition Act (Competition Act), the Commonwealth of Pennsylvania has required the unbundling of retail electric services in Pennsylvania into separate generation, transmission and distribution services with open retail competition for generation services. Since the commencement of deregulation in 1999, PECO serves as the local distribution company providing electric distribution services in its franchised service territory in southeastern Pennsylvania and bundled electric service to customers who do not choose an alternate electric generation supplier. PECO is a wholly owned subsidiary of Exelon Corporation (Exelon) (see Note 3 - Merger). During January 2001, Exelon undertook a corporate restructuring to separate PECO's generation and other competitive businesses from its regulated energy delivery business. As part of the restructuring, the non-regulated operations and related assets and liabilities of PECO, representing the generation and enterprises business segments were transferred to separate subsidiaries of Exelon. As a result, beginning January 2001, the operations of PECO consist of its retail electricity distribution and transmission business in southeastern Pennsylvania and its natural gas distribution business located in the Pennsylvania counties surrounding the City of Philadelphia. As a result of the corporate restructuring, certain risks and commitments and the financial condition and results of operations of PECO have changed significantly. Additionally as a result of the restructuring, PECO is no longer subject to the risks associated with nuclear insurance, decommissioning, spent fuel disposal and energy commitments, other than its purchase power agreement with Exelon Generation Company, LLC (Generation). See Note 19 - Segment Information for additional financial information. Prior to the corporate restructuring effective January 2001, PECO also engaged in the wholesale marketing of electricity on a national basis. Through its Exelon Energy division, PECO was a competitive generation supplier offering competitive energy supply to customers throughout Pennsylvania. PECO's infrastructure services subsidiary, InfraSource, Inc. (InfraSource), formerly Exelon Infrastructure Services, Inc., provided utility infrastructure services to customers in several regions of the United States. PECO owned a 50% interest in AmerGen Energy Company, LLC (AmerGen), a joint venture with British Energy, Inc., a wholly-owned subsidiary of British Energy plc (British Energy), to acquire and operate nuclear generating facilities. PECO also participated in joint ventures which provide communications services in the Philadelphia metropolitan region. As a result of the corporate restructuring effective January 1, 2001, these operations were separated from the regulated energy delivery business. See Note 2 - Corporate Restructuring. BASIS OF PRESENTATION The consolidated financial statements of PECO include the accounts of its majority-owned subsidiaries after the elimination of intercompany transactions. In 2000 and 1999, PECO generally accounted for its 20% to 50% owned investments and joint ventures, in which it exerts significant influence, under the equity method of accounting. In 2000 and 1999, PECO consolidated its proportionate interest in its jointly owned electric utility plants. PECO accounts for its less than 20% owned investments under the cost method of accounting. Accounting policies for regulated operations are in accordance with those prescribed by the 124 regulatory authorities having jurisdiction, principally the Pennsylvania Public Utility Commission (PUC), the Federal Energy Regulatory Commission (FERC) and the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA). ACCOUNTING FOR THE EFFECTS OF REGULATION PECO accounts for all of its regulated electric and gas operations in accordance with the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," (SFAS No. 71) requiring PECO to record in its financial statements the effects of the rate regulation. Use of SFAS No. 71 is applicable to the utility operations of PECO that meet the following criteria: (1) third-party regulation of rates; (2) cost-based rates; and (3) a reasonable assumption that all costs will be recoverable from customers through rates. PECO believes that it is probable that currently recorded regulatory assets will be recovered. If a separable portion of PECO's business no longer meets the provisions of SFAS No. 71, PECO is required to eliminate the financial statement effects of regulation for that portion. USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates have been made in the accounting for unbilled revenue, derivatives, environmental costs, retirement benefit costs and prior to the corporate restructuring, nuclear decommissioning liabilities. REVENUES Operating revenues are generally recorded as service is rendered or energy is delivered to customers. At the end of each month, PECO accrues an estimate for the unbilled amount of energy delivered or services provided to its electric and gas customers. In 2000 and 1999, PECO recognized contract revenues and profits on certain long-term fixed-price contracts from its services businesses under the percentage-of-completion method of accounting based on costs incurred as a percentage of estimated total costs of individual contracts. PURCHASED GAS ADJUSTMENT CLAUSE PECO's natural gas rates are subject to a fuel adjustment clause designed to recover or refund the difference between the actual cost of purchased gas and the amount included in base rates. Differences between the amounts billed to customers and the actual costs recoverable are deferred and recovered or refunded in future periods by means of prospective quarterly adjustments to rates. NUCLEAR FUEL In 2000 and 1999, the cost of nuclear fuel was capitalized and charged to fuel expense using the unit of production method. Estimated costs of nuclear fuel storage and disposal at operating plants were charged to fuel expense as the related fuel was consumed. 125 DEPRECIATION, AMORTIZATION AND DECOMMISSIONING Depreciation is provided over the estimated service lives of property, plant and equipment on a straight line basis. Annual depreciation provisions for financial reporting purposes, expressed as a percentage of average service life for each asset category are presented below:

Asset Category 2001 2000 1999 -------------- ---- ---- ---- Electric-Transmission and Distribution 2.13% 1.82% 1.83% Electric-Generation -- 5.15% 5.12% Gas 2.34% 2.39% 2.36% Common - Gas and Electric 6.26% 3.60% 4.45% Other Property and Equipment 0.60% 7.82% 8.61%

Amortization of regulatory assets is provided over the recovery period as specified in the related regulatory agreement. In 2000 and 1999, goodwill associated with acquisitions was amortized over periods from 10 to 20 years. Accumulated amortization of goodwill was $35 million and $1 million at December 31, 2000 and 1999, respectively. Due to the corporate restructuring, which was effective January 2001, the Goodwill on PECO's Consolidated Balance Sheets was transferred to Exelon Enterprises Company, LLC (Enterprises). CAPITALIZED INTEREST Allowance for Funds Used During Construction (AFUDC) is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC of $2 million, $2 million and $4 million in 2001, 2000 and 1999, respectively, was recorded as a charge to construction work in progress and as a non-cash credit to AFUDC which is included in other income and deductions. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities. PECO uses SFAS No. 34, "Capitalizing Interest Costs," to calculate the costs during construction of debt funds used to finance its non-regulated construction projects. PECO did not record any capitalized interest in 2001, but did record capitalized interest of $2 million and $6 million in 2000 and 1999, respectively. INCOME TAXES Deferred Federal and state income taxes are provided on all significant temporary differences between book bases and tax bases of assets and liabilities, transactions that reflect taxable income in a year different from book income and tax carryforwards. Investment tax credits previously utilized for income tax purposes have been deferred on the Consolidated Balance Sheets and are recognized in book income over the life of the related property. PECO and its subsidiaries file a consolidated Federal income tax return with Exelon. Current and deferred income taxes of the consolidated group are allocated to PECO based on the separate return method. GAINS AND LOSSES ON REACQUIRED DEBT Recoverable gains and losses on reacquired debt related to regulated operations are deferred and amortized to interest expense over the period consistent with rate recovery for ratemaking purposes. In 2000 and 1999, prior to the corporate restructuring, gains and losses on reacquired debt were recognized in PECO's Consolidated Statements of Income as incurred. COMPREHENSIVE INCOME Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to shareholders. Comprehensive Income is reflected in the Consolidated Statements of Comprehensive Income. 126 CASH AND CASH EQUIVALENTS PECO considers all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents. RESTRICTED CASH Restricted cash reflects unused cash proceeds from the issuance of the transition bonds and escrowed cash to be applied to the principal and interest payment on the transition bonds. MARKETABLE SECURITIES Marketable securities are classified as available-for-sale securities and are reported at fair value, with the unrealized gains and losses, net of tax, reported in other comprehensive income. Prior to the corporate restructuring in which PECO's nuclear generating stations were transferred to Generation (See Note 2 - Corporate Restructuring), unrealized gains and losses on marketable securities held in the nuclear decommissioning trust funds were reported in accumulated depreciation. At December 31, 2001 and 2000, PECO had no held-to-maturity or trading securities. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is recorded at cost. PECO evaluates the carrying value of property, plant and equipment and other long-term assets based upon current and anticipated undiscounted cash flows, and recognizes an impairment when it is probable that such estimated cash flows will be less than the carrying value of the asset. Measurement of the amount of impairment, if any, is based upon the difference between carrying value and fair value. The cost of maintenance, repairs and minor replacements of property are charged to maintenance expense as incurred. Upon retirement, the cost of regulated property plus removal costs less salvage value, are charged to accumulated depreciation by the regulated subsidiaries in accordance with regulatory practices. For unregulated property, the cost and accumulated depreciation of property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of the gain or loss on disposition. CAPITALIZED SOFTWARE COSTS Costs incurred during the application development stage of software projects for software which is developed or obtained for internal use are capitalized. At December 31, 2001 and 2000, capitalized software costs totaled $107 million and $131 million, respectively, net of $31 million and $49 million accumulated amortization, respectively. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, not to exceed ten years. DERIVATIVE FINANCIAL INSTRUMENTS PECO accounts for derivative financial instruments under SFAS No. 133 "Accounting for Derivatives and Hedging Activities" (SFAS No. 133). Under the provisions of SFAS No. 133, all derivatives are recognized on the balance sheet at their fair value unless they qualify for a normal purchases and normal sales exception. Changes in the fair value of the derivative financial instruments are recognized in earnings unless specific hedge accounting criteria are met. A derivative financial instrument can be designated as a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge), or a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). Changes in the fair value of a derivative that is highly effective as, and is designated and qualifies as, a fair value hedge, along with the gain or loss on the hedged asset or liability that is attributable to the hedged risk, are recorded in earnings. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as a cash flow hedge are recorded in other comprehensive income, until earnings are affected by the variability of cash flows being hedged. In connection with Exelon's Risk Management Policy (RMP), PECO enters into derivatives to manage its exposure to fluctuation in interest rates related to its variable rate debt 127 instruments, changes in interest rates related to planned future debt issuances prior to their actual issuance and changes in the fair value of outstanding debt which is planned for early retirement. For 2000 and 1999, prior to the corporate restructuring, PECO utilized derivatives to manage the utilization of its available generating capability and provisions of wholesale energy to its affiliates. PECO also utilized energy option contracts and energy financial swap arrangements to limit the market price risk associated with forward energy commodity contracts. Prior to the adoption of SFAS No. 133, PECO applied hedge accounting only if the derivative reduced the risk of the underlying hedged item and was designated at the inception of the hedge, with respect to the hedged item. PECO recognized any gains or losses on these derivatives when the underlying physical transaction affected earnings. NEW ACCOUNTING PRONOUNCEMENTS In 2001, the FASB issued SFAS No. 141, "Business Combinations" (SFAS No. 141), SFAS No. 142 "Goodwill and Other Intangible Assets"(SFAS 142), SFAS No. 143, "Asset Retirement Obligations" (SFAS No. 143), and SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No.144). SFAS No. 141 requires that all business combinations be accounted for under the purchase method of accounting and establishes criteria for the separate recognition of intangible assets acquired in business combinations. SFAS No. 141 is effective for business combinations initiated after June 30, 2001. SFAS No. 142 establishes new accounting and reporting standards for goodwill and intangible assets. SFAS No. 142 is effective as of January 1, 2002. Under SFAS No. 142, effective January 1, 2002, goodwill recorded is no longer subject to amortization. After January 1, 2002, goodwill will be subject to an assessment for impairment using a two-step fair value based test, the first step of which must be performed at least annually, or more frequently if events or circumstances indicate that goodwill might be impaired. The first step compares the fair value of a reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step compares the carrying amount of the goodwill to the fair value of the goodwill. If the fair value of goodwill is less than the carrying amount, an impairment loss would be reported as a reduction to goodwill and a charge to operating expense, except at the transition date, when the loss would be reflected as a cumulative effect of a change in accounting principle. As of December 31, 2001, PECO does not have any Goodwill reflected on its Consolidated Balance Sheets. As a result of the corporate restructuring in January 2001, the goodwill was transferred to Enterprises. SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. PECO expects to adopt SFAS No. 143 on January 1, 2003. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. PECO is in the process of evaluating the impact of SFAS No. 143 on its financial statements. SFAS No. 144 establishes accounting and reporting standards for both the impairment and disposal of long-lived assets. This statement is effective for fiscal years beginning after December 15, 2001 and provisions of this statement are generally applied prospectively. PECO is in the process of evaluating the impact of SFAS No. 144 on its financial statements, and does not expect the impact to be material. RECLASSIFICATIONS Certain prior year amounts have been reclassified for comparative purposes. The reclassifications did not affect net income. 2. CORPORATE RESTRUCTURING During January 2001, Exelon undertook a restructuring to separate it's generation and other competitive businesses from its regulated energy delivery business. As part of the restructuring, 128 the non-regulated operations and related assets and liabilities of PECO, representing PECO's generation and enterprises business segments, were transferred to Generation and Enterprises, respectively. Additionally, certain operations and assets and liabilities of PECO were transferred to Exelon Business Services Company (BSC). As a result, effective January 1, 2001, the operations of PECO consist of its retail electricity distribution and transmission business in southeastern Pennsylvania, and its natural gas distribution business in the Pennsylvania counties surrounding the City of Philadelphia. The corporate restructuring had the following effect on PECO's Consolidated Balance Sheet:

Decrease in Assets: Current Assets $(1,085) Property, Plant and Equipment, net (1,212) Investments (1,262) Other Noncurrent Assets (431) (Increase) Decrease in Liabilities: Current Liabilities 1,540 Long-Term Debt 205 Deferred Income Taxes (441) Other Noncurrent Liabilities 1,003 ------- Net Assets Transferred $(1,683) =======

Consideration, based on the net book value of the net assets transferred, was as follows:

Return of Capital $1,608 Note Receivable 75 ------ $1,683 ======

In connection with the transfer, PECO entered into a power purchase agreement (PPA) with Generation. Under the terms of the PPA, PECO obtains the majority of its electric supply from Generation through 2010. Also, under the terms of the transfer, PECO assigned its rights and obligations under various PPAs and fuel supply agreements to Generation. Generation supplies power to PECO from the transferred generation assets, assigned PPAs and other market sources. As a result of the corporate restructuring, certain risks and commitments that have been disclosed in Note 18 - Commitments and Contingencies and the future financial condition and results of operations will change significantly. On a prospective basis, PECO will not be subject to the risks associated with nuclear insurance, decommissioning, spent fuel disposal and energy commitments, other than its purchase power agreement with Generation. See Note 19 - Segment Information for additional financial information. 3. MERGER On October 20, 2000, Exelon became the parent corporation of PECO and Commonwealth Edison Company (ComEd) as a result of the completion of the transactions contemplated by an Agreement and Plan of Exchange and Merger, as amended (Merger Agreement), among PECO, Unicom Corporation (Unicom) and Exelon. As a result of the share exchange, Exelon became the owner of all of the common stock of PECO. Following the share exchange, pursuant to the Merger Agreement, Unicom merged with and into Exelon (Merger). In the Merger, each share of the outstanding common stock of Unicom was converted into 0.875 shares of common stock of 129 Exelon plus $3.00 in cash. As a result of the Merger, Unicom ceased to exist and its subsidiaries, including ComEd, became subsidiaries of Exelon. MERGER-RELATED COSTS Merger-related costs charged to expense in 2000 were $248 million, consisting of $132 million of direct incremental costs and $116 million for PECO employee costs. Direct incremental costs represent expenses directly associated with completing the Merger, including professional fees, regulatory approval and settlement costs, and settlement of compensation arrangements. Employee costs represent estimated severance costs and pension and postretirement benefits provided under Exelon's Merger Separation Plan (MSP) for eligible employees who are expected to be involuntarily terminated by December 2002 due to integration activities of the merged companies. 4. ACQUISITIONS SITHE ENERGIES, INC. ACQUISITION On December 18, 2000, PECO acquired 49.9% of the outstanding common stock of Sithe Energies, Inc. (Sithe) through an intercompany transaction with Exelon for $696 million in cash and $8 million of acquisition costs. The transaction includes an option to purchase the remaining common stock outstanding exercisable between December 2002 and December 2005, at a price to be determined based on prevailing market conditions. Sithe is an independent power generator in North America utilizing primarily fossil and hydro generation. The purchase involves approximately 10,000 megawatts (MW) of generation consisting of 3,800 MW of existing merchant generation, 2,500 MW under construction, and another 3,700 MW of generation in various stages of development, as well as Sithe's domestic marketing and development businesses. The generation assets are located primarily in Massachusetts and New York, but also include plants in Pennsylvania, California, Colorado and Idaho, as well as Canada and Mexico. In conjunction with the corporate restructuring in January 2001, PECO transferred its investment in Sithe and the purchase option to Generation. INFRASOURCE, INC. ACQUISITIONS In 2000, InfraSource, Inc. (InfraSource), an unregulated majority owned subsidiary of PECO, formerly Exelon Infrastructure Services, Inc., acquired the stock or assets of seven utility service contracting companies for an aggregate purchase price of approximately $245 million, net of cash acquired of $9 million, including InfraSource common stock valued at $14 million. The acquisitions were accounted for using the purchase method of accounting. The initial estimate of the excess of purchase price over the fair value of net assets acquired (goodwill) was approximately $216 million. The allocation of purchase price to the fair value of assets acquired and liabilities assumed in these acquisitions is as follows:

Current Assets (net of cash acquired) $ 63 Property, Plant and Equipment 17 Goodwill 216 Current Liabilities (51) ----- Total $ 245 =====

At December 31, 2000 current assets included $70 million of costs and earnings in excess of billings on uncompleted contracts and current liabilities includes $23 million of billings and earnings in excess of costs on uncompleted contracts, related to InfraSource. 130 In conjunction with the corporate restructuring in January 2001, PECO transferred InfraSource to Enterprises. AMERGEN ENERGY COMPANY, LLC In August 2000, AmerGen completed the purchase of Oyster Creek Nuclear Generating Facility (Oyster Creek) from GPU, Inc. (GPU) for $10 million. Under the terms of the purchase agreement, GPU agreed to fund outage costs not to exceed $89 million, including the cost of fuel, for a refueling outage that occurred in 2000. AmerGen is repaying these costs to GPU in nine equal annual installments through 2009. In addition, AmerGen assumed full responsibility for the ultimate decommissioning of Oyster Creek. At the closing of the sale, GPU provided funding for the decommissioning trust of $440 million. In conjunction with this acquisition, AmerGen has received a fully funded decommissioning trust fund which has been computed assuming the anticipated costs to appropriately decommission Oyster Creek discounted to net present value using the NRC's mandated rate of 2%. AmerGen believes that the amount of the trust fund and investment earnings thereon will be sufficient to meet its decommissioning obligation. GPU is purchasing the electricity generated by Oyster Creek pursuant to a three-year PPA. In conjunction with the corporate restructuring in January 2001, PECO transferred its investment in AmerGen to Generation. 5. ACCOUNTING CHANGES On January 1, 2001, PECO recognized a deferred non-cash gain of $40 million (net of income taxes of $29 million), in accumulated other comprehensive income, a component of shareholders' equity, to reflect the adoption of SFAS No. 133, as amended. During the fourth quarter of 2000, as a result of the synchronization of accounting policies with Unicom in connection with the Merger, PECO changed its method of accounting for nuclear outage costs to record such costs as incurred. Previously, PECO accrued these costs over the operating unit cycle. As a result of the change in accounting method for nuclear outage costs, PECO recorded income of $24 million (net of income taxes of $16 million). The change is reported as a Cumulative Effect of a Change in Accounting Principle on the Consolidated Statements of Income as of December 31, 2000, representing the balance of the nuclear outage cost reserve at January 1, 2000. 6. REGULATORY ISSUES In 2001, the phased process to implement competition in the electric industry continued as mandated by the requirements of the PUC's Final Restructuring Order. Customer Choice The PUC's Final Restructuring Order provided for the phase-in of customer choice of electric generation supplier (EGS) for all customers by January 1, 2000. The Final Restructuring Order also established market share thresholds to ensure that a minimum number of residential and commercial customers choose an EGS or a PECO affiliate. If less than 35% and 50% of residential and commercial customers have chosen an EGS, including residential customers assigned to an EGS as a provider of last resort default supplier, by January 1, 2001 and January 1, 2003, respectively, the number of customers sufficient to meet the necessary threshold levels shall be randomly selected and assigned to an EGS through a PUC-determined process. On January 1, 2001, the 35% threshold was met for all three customer classes as a result of agreements assigning customers to New Power Company and Green Mountain Energy Company as providers of last resort default service. During 2001, PECO experienced an increase in the number of customers selecting or returning to PECO as their EGS and at December 31, 2001, approximately 28% of PECO's residential load, 6% of its small commercial and industrial load and 5% of its large commercial and industrial load were purchasing generation from an 131 alternative generation supplier. Customers who purchase energy from an EGS continue to pay a delivery charge. Rate Reductions and Caps Under the Final Restructuring Order, retail electric rates were capped at year-end 1996 levels (system-wide average of 9.96 cents/kilowatt hour (kWh)) through June 2005. The Final Restructuring Order required PECO to reduce its retail electric rates by 8% from the 1996 system-wide average rate on January 1, 1999. This rate reduction decreased to 6% on January 1, 2000 until January 1, 2001. The transmission and distribution rate component was capped at a system-wide average rate of 2.98 cents/kWh through June 30, 2005. Additionally, generation rate caps, defined as the sum of the applicable transition charge and energy and capacity charge, remain in effect through 2010. On March 16, 2000, the PUC issued an order authorizing PECO to securitize up to an additional $1 billion of its authorized stranded costs recovery. In accordance with the terms of that order, PECO provided its retail customers with rate reductions of $60 million for calendar year 2001 only. Under a comprehensive settlement agreement in connection with achieving regulatory approval of the Merger, PECO agreed to $200 million in aggregate rate reductions for all customers in Pennsylvania over the period January 1, 2002 through 2005 and extended the rate caps on PECO's retail electric distribution charges through December 31, 2006. 7. SUPPLEMENTAL FINANCIAL INFORMATION SUPPLEMENTAL INCOME STATEMENT INFORMATION

For the Years Ended December 31, -------------------------------- 2001 2000 1999 ---- ---- ---- TAXES OTHER THAN INCOME Utility $ 135 $ 144 $ 155 Real estate 12 45 72 Payroll 12 27 28 Other 2 21 7 ------ ----- ------ Total $ 161 $ 237 $ 262 ====== ===== ====== OTHER, NET Investment income $ 24 $ 50 $ 52 Gain (loss) on disposition of assets, net 6 (20) (1) Settlement of power purchase agreement -- 6 -- AFUDC, equity and borrowed 2 2 4 Other income (expense) 4 3 4 ------ ----- ------ Total $ 36 $ 41 $ 59 ====== ===== ======

132 SUPPLEMENTAL CASH FLOW INFORMATION

For the Years Ended December 31, -------------------------------- 2001 2000 1999 ---- ---- ---- Cash paid during the year: Interest (net of amount capitalized) $ 416 $ 431 $ 350 Income taxes (net of refunds) $ 271 $ 261 $ 304 Non-cash investing and financing: Contribution of Receivable from Parent $ 1,878 -- -- Net Assets Transferred as a Result of Restructuring $ 1,608 -- -- Investment in Sithe -- $ 696 -- Issuance of InfraSource stock $ -- $ 14 $ 11 Depreciation and amortization: Property, plant and equipment $ 135 $ 229 $ 207 Nuclear fuel -- 112 104 Regulatory assets 275 57 -- Decommissioning 6 29 29 Goodwill -- 10 1 Leased property -- -- 17 -------- ------- -------- Total Depreciation and Amortization $ 416 $ 437 $ 358 ======== ======= ========

SUPPLEMENTAL BALANCE SHEET INFORMATION

at December 31, --------------- 2001 2000 ---- ---- INVESTMENTS Investment in Sithe $ -- $ 704 Energy services and other ventures -- 39 Communication ventures -- 35 Investment in AmerGen -- 44 Other Investments 24 25 ------- -------- Total $ 24 $ 847 ======= ======== REGULATORY ASSETS Competitive transition charge $ 4,947 $ 5,218 Recoverable deferred income taxes (see Note 12) 675 661 Loss on reacquired debt 58 64 Compensated absences 5 5 Non-pension postretirement benefits 71 78 ------- -------- Long-Term Regulatory Assets 5,756 6,026 Deferred energy costs (current asset) 56 86 ------- -------- Total $ 5,812 $ 6,112 ======= ========

At December 31, 2001 and 2000, the Competitive Transition Charge (CTC) includes the unamortized balance of $4.5 billion and $4.8 billion, respectively, of Intangible Transition Property (ITP) sold to PECO Energy Transition Trust (PETT), a wholly owned subsidiary of PECO, in connection with the securitization of PECO's stranded cost recovery. PETT financed its purchase of the ITP through the issuance of transition bonds. See Note 11 - Long-Term Debt. 133 ITP represents the irrevocable right of PECO or its assignee to collect non-bypassable charges from customers to recover stranded costs. The CTC represents PECO's stranded costs that are recoverable through regulated rates. The CTC is recoverable over a twelve-year period ending December 31, 2010 with a return on the unamortized balance of 10.75%. 8. ACCOUNTS RECEIVABLE Accounts receivable -- Customer at December 31, 2001 and 2000 included unbilled operating revenues of $100 million and $180 million, respectively. The allowance for uncollectible accounts at December 31, 2001 and 2000 was $110 million and $131 million, respectively. Accounts receivable -- Other at December 31, 2000 included demand notes receivable from a communications joint venture in the amount of $153 million. The receivable has been adjusted for PECO's share of this joint venture's operating losses incurred in excess of its investment. The notes bear interest at the Applicable Federal Rate, compounded semi-annually. The average interest rate on the notes receivable was 6.22% at December 31, 2000. Interest income related to the notes receivable was $10 million in 2000. In conjunction with the corporate restructuring in January 2001, these demand notes were transferred to Enterprises. PECO is party to an agreement with a financial institution under which it can sell or finance with limited recourse an undivided interest, adjusted daily, in up to $225 million of designated accounts receivable until November 2005. At December 31, 2001, PECO had sold a $225 million interest in accounts receivable, consisting of a $170 million interest in accounts receivable which PECO accounted for as a sale under SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - a Replacement of FASB Statement No. 125," and a $55 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable. See Note 11 - Long-Term Debt. PECO retains the servicing responsibility for these receivables. The agreement requires PECO to maintain the $225 million interest, which, if not met, requires PECO to deposit cash in order to satisfy such requirements. At December 31, 2001 and 2000, PECO met this requirement and was not required to make any cash deposits. 9. PROPERTY, PLANT, AND EQUIPMENT A summary of property, plant and equipment by classification as of December 31, 2001 and 2000 is as follows:

Asset Category 2001 2000 -------------- ---- ---- Electric-Transmission and Distribution $4,058 $3,836 Electric-Generation -- 2,086 Gas 1,281 1,181 Common 399 408 Nuclear Fuel -- 1,664 Construction Work in Progress 88 498 Leased Property -- 2 Other Property, Plant and Equipment 20 197 ------ ------ Total Property, Plant and Equipment 5,846 9,872 Less Accumulated Depreciation 1,799 4,714 ------ ------ Property, Plant and Equipment, net $4,047 $5,158 ====== ======

Accumulated depreciation included accumulated amortization of nuclear fuel of $1.4 billion, as well as the nuclear decommissioning liability for the nuclear operating units of $406 million as of December 31, 2000. 134 The decrease in the net property, plant and equipment balance from the prior year was primarily due to the corporate restructuring in which PECO's generation and enterprise assets were transferred to separate subsidiaries of Exelon (see Note 2 - Corporate Restructuring). 10. NOTES PAYABLE

2001 2000 1999 ---- ---- ---- Average borrowings $ 3 $ 186 $ 242 Average interest rates, computed on daily basis 2.99% 6.62% 5.62% Maximum borrowings outstanding $ 471 $ 500 $ 728 Average interest rates, at December 31 2.25% 7.18% 6.80%

PECO, along with Exelon, ComEd and Generation, is a party to a $1.5 billion 364-day unsecured revolving credit facility on December 12, 2001 with a group of banks. PECO has a $300 million sublimit under this credit facility, which is used principally to support PECOs commercial paper program. At December 31, 2001 and 2000, the amount of commercial paper outstanding was $101 million and $161 million, respectively. At December 31, 2001 and 2000, there were no borrowings under this credit facility. Interest rates on borrowings under the credit facility are based on the London Interbank Offering Rate as of the date of the advance. 135 11. LONG-TERM DEBT

at December 31, 2001 at December 31, -------------------- --------------- Maturity Rates Date 2001 2000 ----------- --------- -------- -------- PETT Bonds Series 1999-A: Fixed rates 5.63%-6.13% 2003-2007 (a) $ 2,577 $ 2,706 Floating rates 2.11%-2.18% 2003-2007 (a) 310 1,132 PETT Bonds Series 2000-A: 7.3%-7.65% 2002-2009 (a) 890 1,000 PETT Bonds Series 2001: 6.52% 2010 (a) 805 -- First and Refunding Mortgage Bonds (b) (c): Fixed rates 5.95%-8.00% 2002-2022 1,027 1,148 Floating rates 1.35%-2.35% 2012 154 154 Notes payable 7.25% 2003-2004 -- 14 Pollution control notes: Fixed rates 5.20%-5.30% 2021-2034 157 157 Floating rates 1.75% 2027 17 212 Notes payable - accounts receivable agreement 2.00% 2005 55 40 -------- -------- TOTAL LONG-TERM DEBT (d) 5,992 6,563 Unamortized debt discount and premium, net (6) (8) Due within one year (548) (553) LONG-TERM DEBT $ 5,438 $ 6,002 ======== ========

(a) The maturity date represents the expected final payment date which is the date when all principal and interest of the related class of transition bonds is expected to be paid in full in accordance with the expected amortization schedule for the applicable class. The date when all principal and interest must be paid in full for the PETT Bonds Series 1999-A, 2000-A and 2001-A are 2003 through 2009, 2003 through 2010 and 2010, respectively. The current portion of transition bonds is based upon the expected maturity date. (b) Utility plant of PECO is subject to the lien of its mortgage indenture. (c) Includes first mortgage bonds issued under the PECO mortgage indenture securing pollution control notes. (d) Long-term debt maturities in the period 2002 through 2006 and thereafter are as follows: 2002 $ 548 2003 690 2004 318 2005 503 2006 500 Thereafter 3,433 ------ Total $5,992 In 2001, PECO Energy Transition Trust (PETT), a Delaware business trust and a wholly owned subsidiary of PECO, refinanced $805 million of floating rate Series 1999-A Transition Bonds through the issuance by PETT of fixed-rate transition bonds (Series 2001-A Transition Bonds). Approximately 72% of Class A-3 and 70% of the Class A-5 Series 1999-A Transition Bonds were redeemed. The Series 2001-A Transition Bonds are non-callable, fixed-rate securities with an interest rate of 6.52%. The Series 2001-A Transition Bonds have an expected final payment date of September 1, 2010 and a termination date of December 31, 2010. Also in 2001, PECO issued, through a private placement, $250 million of its First and Refunding Mortgage Bonds, with an interest rate of 5.95% and a maturity date of November 11, 2011. Proceeds from the first mortgage bonds were used to repay a $250 million aggregate principal amount of PECO's First and Refunding Mortgage Bonds having an interest rate of 5.625% and a maturity date of November 1, 2001. In 1999, PECO entered into treasury forwards associated with the anticipated issuance of the Series 2000-A Transition Bonds. On May 2, 2000, these instruments were settled with net 136 proceeds to the counterparties of $13 million which has been deferred and is being amortized over the life of the Series 2000-A Transition Bonds as an increase to interest expense. In 1998, PECO entered into treasury forwards and forward-starting interest rate swaps to manage interest rate exposure associated with the anticipated issuance of the Series 1999-A Transition Bonds. On March 18, 1999, these instruments were settled with net proceeds of $80 million to PECO which were deferred and are being amortized over the life of the Series 1999-A Transition Bonds as a reduction of interest expense. In connection with the refinancing of a portion of the two floating rate series of transition bonds in the first quarter of 2001, PECO settled $318 million of a forward-starting interest rate swap resulting in a $6 million gain which is reflected in other income and deductions due to the transaction no longer being probable. Also, in connection with the refinancing, PECO settled a portion of the interest rate swaps and the remaining portion of the forward-starting interest rate swaps resulting in gains of $25 million, which were deferred and are being amortized over the expected remaining lives of the related debt. At December 31, 2001 and 2000, the aggregate unamortized net gain on the settlement of PECO transactions was $55 million and $51 million, respectively. In 2000 and 1999, PECO incurred extraordinary charges aggregating $6 million ($4 million, net of tax) and $62 million ($37 million, net of tax), respectively for prepayment premiums and the write-offs of unamortized deferred financing costs associated with the early retirement of debt. 12. INCOME TAXES Income tax expense (benefit) is comprised of the following components:

For the Year Ended December 31, ----------------------------------------- 2001 2000 1999 ------ ------ ------ Included in operations: Federal Current $ 255 $ 181 $ 293 Deferred (49) 91 6 Investment tax credit, net (3) (15) (14) State Current 8 2 72 Deferred (14) 11 1 ------ ------ ------ $ 197 $ 270 $ 358 ====== ====== ====== Included in extraordinary item: Federal Current $ -- $ (2) $ (19) State Current -- -- (6) ------ ------ ------ $ -- $ (2) $ (25) ====== ====== ====== Included in cumulative effects of changes in accounting principles: Federal Deferred $ -- $ 13 $ -- State Deferred -- 3 -- ------ ------ ------ $ -- $ 16 $ -- ====== ====== ======

137 The effective income tax rate varies from the U.S. Federal statutory rate for the years ended December 31 principally due to the following:

For the Year Ended December 31, ------------------------------------ 2001 2000 1999 ---- ---- ---- U.S. Federal statutory rate 35.0% 35.0% 35.0% Increase (decrease) due to: Plant basis differences (0.8) (0.8) (0.8) State income taxes, net of Federal income tax benefit (0.6) 2.7 4.8 Amortization of investment tax credit (0.4) (1.9) (1.6) Prior period income taxes (1.5) 0.5 (0.7) Other, net -- 0.2 (0.1) ---- ---- ---- Effective income tax rate 31.7% 35.7% 36.6% ==== ==== ====

The tax effects of temporary differences giving rise to significant portions of PECO's deferred tax assets and liabilities as of December 31, 2001 and 2000 are presented below:

2001 2000 ---- ---- Deferred tax liabilities: Plant basis difference $ 2,990 $ 2,839 Deferred investment tax credit 27 271 Deferred debt refinancing costs 31 34 ------- -------- Total deferred tax liabilities 3,048 3,144 ------- -------- Deferred tax assets: Deferred pension and postretirement obligations (12) (187) Other, net (44) (127) ------- -------- Total deferred tax assets (56) (314) ------- -------- Deferred income taxes (net) on the balance sheet $ 2,992 $ 2,830 ======= ========

In accordance with regulatory treatment of certain temporary differences, PECO has recorded a regulatory asset for recoverable deferred income taxes of $675 million and $661 million at December 31, 2001 and 2000, respectively. These recoverable deferred income taxes include the deferred tax effects associated principally with liberalized depreciation accounted for in accordance with the ratemaking policies of the PUC, as well as the revenue impacts thereon, and assume continued recovery of these costs in future rates. The Internal Revenue Service and certain state tax authorities are currently auditing certain tax returns of PECO. The current audits are not expected to have an adverse impact on financial condition or results of operations of PECO. 13. RETIREMENT BENEFITS PECO has adopted defined benefit pension plans and postretirement welfare benefit plans sponsored by Exelon. Essentially all PECO employees are eligible to participate in these plans. In 2001, PECO's former plans were consolidated into the Exelon plans. Essentially all PECO employees, hired on or after January 1, 2001 are eligible to participate in newly established Exelon cash balance pension plans. Employees who were active participants in the former PECO pension plans on December 31, 2000 and remain employed by PECO on January 1, 2002, will have the opportunity to continue to participate in the pension plan or to transfer to the cash balance plan. Benefits under these pension plans generally reflect each employee's compensation, years of service, and age at retirement. Funding is based upon actuarially determined contributions that take into account the amount deductible for income tax purposes 138 and the minimum contribution required under the Employee Retirement Income Security Act of 1974, as amended. The following tables provide a reconciliation of benefit obligations, plan assets, and funded status for PECO's proportionate allocated interest in the plans.

Other Pension Benefits Postretirement Benefits --------------------- ----------------------- 2001 2000 2001 2000 ---- ---- ---- ---- Change in Benefit Obligation: Net benefit obligation at beginning of year $ 2,230 $ 2,054 $ 922 $ 798 Service cost 11 24 9 18 Interest cost 84 158 43 66 Plan amendments 20 -- -- -- Actuarial (gain)loss 11 140 92 69 Curtailments/Settlements 2 (74) -- 4 Special accounting costs(benefit) (16) 96 (2) 11 Gross benefits paid (93) (168) (24) (44) Corporate Restructuring Transfer (1,206) -- (499) -- -------- ------- --------- -------- Net benefit obligation at end of year $ 1,043 $ 2,230 $ 541 $ 922 ======== ======= ========= ======== Change in Plan Assets: Fair value of plan assets at beginning of year $ 3,005 $ 2,982 $ 263 $ 244 Actual return on plan assets (59) 190 (2) 8 Employer contributions 9 1 26 54 Plan participants' contributions -- -- -- 1 Gross benefits paid (93) (168) (24) (44) Corporate Restructuring Transfer (1,625) -- (142) -- -------- ------- --------- -------- Fair value of plan assets at end of year $ 1,237 $ 3,005 $ 121 $ 263 ======== ======= ========= ======== Funded status at end of year $ 194 $ 775 $ (420) $ (659) Unrecognized net actuarial (gain)loss (225) (960) 132 36 Unrecognized prior service cost 51 77 -- -- Unrecognized net transition obligation (asset) (7) (21) 49 122 -------- ------- --------- -------- Net asset (liability) recognized at end of year $ 13 $ (129) $ (239) $ (501) ======== ======= ========= ========

Pension Benefits Other Postretirement Benefits ------------------------------- ----------------------------- 2001 2000 1999 2001 2000 1999 ---- ---- ---- ---- ---- ---- WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31, Discount rate 7.35% 7.60% 8.00% 7.35% 7.60% 8.00% Expected return on plan assets 9.50% 9.50% 9.50% 9.50% 8.00% 8.00% Rate of compensation increase 4.00% 5.00% 5.00% 4.00% 4.30% 5.00% Health care cost trend on covered charges N/A N/A N/A 10.00% 7.00% 8.00% decreasing decreasing decreasing to ultimate to ultimate to ultimate trend of trend of trend of 4.5% in 2008 5.0% in 2005 5.0% in 2006

139

Pension Benefits Other Postretirement Benefits ------------------------------- ------------------------------ 2001 2000 1999 2001 2000 1999 ---- ---- ---- ---- ---- ---- COMPONENTS OF NET PERIODIC BENEFIT COST (BENEFIT): Service cost $ 12 $ 25 $ 29 $ 10 $ 18 $ 19 Interest cost 84 158 154 43 66 57 Expected return on assets (131) (238) (222) (11) (18) (16) Amortization of: Transition obligation (asset) (2) (5) (4) 6 12 12 Prior service cost 4 7 5 -- -- -- Actuarial (gain) loss (13) (26) (8) -- -- -- Curtailment charge (credit) 1 (12) -- (5) 24 -- Settlement charge (credit) (1) (16) -- -- -- -- ----- ------ ------ ---- ------ ----- Net periodic benefit cost (benefit) $ (46) $ (107) $ (46) $ 43 $ 102 $ 72 ===== ====== ====== ==== ====== ===== Special accounting costs $ 16 $ 96 $ -- $ (2) $ 11 $ -- ===== ====== ====== ==== ====== =====

SENSITIVITY OF RETIREE WELFARE RESULTS Effect of a one percentage point increase in assumed health care cost trend on total service and interest cost components $ 7 on postretirement benefit obligation $ 59 Effect of a one percentage point decrease in assumed health care cost trend on total service and interest cost components $ (6) on postretirement benefit obligation $ (50) The decrease in the net benefit obligation and the fair value of plan assets in 2001 as compared to 2000 is due primarily to the corporate restructuring (See Note 2 - Corporate Restructuring). Amounts of the obligation allocated to affiliates in the restructuring were primarily based on the relative number of active employees transferred to each affiliate. Prior service cost is amortized on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans. Special accounting costs of $16 million and $96 million in 2001 and 2000, respectively, represent accelerated separation and enhancement benefits provided to PECO employees expected to be terminated as a result of the Merger. PECO provides certain health care and life insurance benefits for retired employees through plans sponsored by Exelon. Welfare benefits for active employees are provided by several insurance policies or self-funded plans whose premiums or contributions are based upon the benefits paid during the year. PECO has savings plans for the majority of its employees. The plans allow employees to contribute a portion of their pretax income in accordance with specified guidelines. PECO matches a percentage of the employee contribution up to certain limits. The cost of PECO's matching contribution to the savings plans totaled $7 million, $11 million and $7 million in 2001, 2000, and 1999, respectively. 140 14. PREFERRED AND PREFERENCE STOCK At December 31, 2001 and 2000, Series Preference Stock of PECO, no par value, consisted of 100,000,000 shares authorized, of which no shares were outstanding. At December 31, 2001 and 2000, cumulative Preferred Stock of PECO, no par value, consisted of 15,000,000 shares authorized and the amounts set forth below:

at December 31, ----------------------- 2001 2000 2001 2000 Current Redemption ---- ---- ---- ---- Price(a) Shares Outstanding Amount -------- ------------------ ------ SERIES (WITHOUT MANDATORY REDEMPTION) $4.68 $ 104.00 150,000 150,000 $ 15 $ 15 $4.40 112.50 274,720 274,720 27 27 $4.30 102.00 150,000 150,000 15 15 $3.80 106.00 300,000 300,000 30 30 $7.48 (b) 500,000 500,000 50 50 ----- -------- --------- --------- ----- ------ 1,374,720 1,374,720 137 137 SERIES (WITH MANDATORY REDEMPTION) $6.12 (c) 185,400 370,800 19 37 ----- -------- --------- --------- ----- ------ Total preferred stock 1,560,120 1,745,520 $ 156 $ 174 ========= ========= ===== ======

(a) Redeemable, at the option of PECO, at the indicated dollar amounts per share, plus accrued dividends. (b) None of the shares of this series is subject to redemption prior to April 1, 2003. (c) PECO made the annual sinking fund payments of $18.5 million on August 1, 2001 and August 2, 2000. The future sinking fund requirement in 2002 is $18.5 million. 15. COMPANY - OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF A PARTNERSHIP At December 31, 2001 and 2000, PECO Energy Capital, L.P. (Partnership), a Delaware limited partnership of which a wholly owned subsidiary of PECO is the sole general partner, had outstanding Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS) as set forth in the following table:

Mandatory Distri- Liqui- at December 31, Redemption bution dation 2001 2000 2001 2000 Date Rate Value Trust Securities Outstanding Amount ---------- ------ -------- ---------------------------- ------ ------ PECO Energy Capital Trust II 2037 8.00% $ 25 2,000,000 2,000,000 $ 50 $ 50 PECO Energy Capital Trust III 2028 7.38% 1,000 78,105 78,105 78 78 ------------ ---------- ----- ------ Total 2,078,105 2,078,105 $ 128 $ 128 ============ ========== ===== ======

The securities issued by the PECO trusts represent Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS) having a distribution rate and liquidation value equivalent to the trust securities. The COMRPS are the sole assets of these trusts and represent limited partnership interests of PECO Energy Capital, L.P. (Partnership), a Delaware limited partnership. Each holder of a trust's securities is entitled to withdraw the corresponding number of COMRPS from the trust in exchange for the trust securities so held. Each series of COMRPS is supported by PECO's deferrable interest subordinated debentures, held by the Partnership, which bear interest at rates equal to the distribution rates on the related series of COMRPS. The interest expense on the debentures is included in Other Income and Deductions in the Consolidated Statements of Income and is deductible for income tax purposes. 141 16. COMMON STOCK At December 31, 2001 and 2000, common stock without par value consisted of 600,000,000 and 600,000,000 shares authorized and 170,478,507 and 170,478,507 shares outstanding, respectively. STOCK REPURCHASE In January 2000, in connection with the Merger Agreement, PECO entered into a forward purchase agreement to purchase $500 million of its common stock from time to time. Settlement of this forward purchase agreement was, at PECO's election, on a physical, net share or net cash basis. In May 2000, PECO utilized a portion of the proceeds from the securitization of its stranded cost recovery to physically settle this agreement, resulting in the repurchase of 12 million shares of common stock for $496 million. In connection with the settlement of this agreement, PECO received $1 million in accumulated dividends on the repurchased shares and paid $6 million of interest. During 1997, PECO's Board of Directors authorized the repurchase of up to 25 million shares of its common stock from time to time through open-market, privately negotiated and/or other types of transactions in conformity with the rules of the SEC. Pursuant to these authorizations, PECO entered into forward purchase agreements to be settled from time to time, at PECO's election, on a physical, net share or net cash basis. PECO utilized the proceeds from the securitization of a portion of its stranded cost recovery in the first quarter of 1999, to physically settle these agreements, resulting in the purchase of 21 million shares of common stock for $696 million. In connection with the settlement of these agreements, PECO received $18 million in accumulated dividends on the repurchased shares and paid $6 million of interest. Shares Outstanding The following table details PECO's common stock and treasury stock:

Common Treasury (in thousands) Shares Shares -------------- ------ ------ Balance, December 31, 1998 224,684 -- Long Term Incentive Plan Issuances 670 -- Common Stock Repurchases -- 44,082 ------- ------ Balance, December 31, 1999 225,354 44,082 Long Term Incentive Plan Issuances -- (195) Cancellation of Treasury Shares (54,875) (54,875) Common Stock Repurchases -- 11,950 Stock Option Exercises -- (962) ------- ------ Balance, December 31, 2000 170,479 -- ------- ------ Balance, December 31, 2001 170,479 -- ======= ======

142 17. FAIR VALUE OF FINANCIAL ASSETS AND LIABILITIES The carrying amounts and fair values of PECO's financial assets and liabilities as of December 31, 2001 and 2000 were as follows:

2001 2000 ------------------------- -------------------------- Carrying Carrying Amount Fair Value Amount Fair Value ------ ---------- ------ ---------- NON-DERIVATIVES: Liabilities Long-term debt (including amounts due within one year) $ 5,986 $ 6,199 $ 6,555 $ 6,797 COMRPS $ 128 $ 127 $ 128 $ 122 Mandatorily Redeemable Preferred Stock $ 19 $ 10 $ 37 $ 30 DERIVATIVES: Interest rate swaps $ (19) $ (19) -- $ (19) Forward interest rate swaps -- -- -- $ 40

Cash and cash equivalents, customer accounts receivable and trust accounts for decommissioning nuclear plants are recorded at their fair value. As of December 31, 2001 and 2000, PECO's carrying amounts of cash and cash equivalents and accounts receivable are representative of fair value because of the short-term nature of these instruments. Fair values of the trust accounts for decommissioning nuclear plants, long-term debt, COMRPS and Mandatorily Redeemable Preferred Stock are estimated based on quoted market prices for the same or similar issues. The fair value of PECO's interest rate swaps and power purchase and sale contracts is determined using quoted exchange prices, external dealer prices, or internal valuation models which utilize assumptions of future energy prices and available market pricing curves. Financial instruments that potentially subject PECO to concentrations of credit risk consist principally of cash equivalents and customer accounts receivable. PECO places its cash equivalents with high-credit quality financial institutions. Generally, such investments are in excess of the Federal Deposit Insurance Corporation limits. Concentrations of credit risk with respect to customer accounts receivable are limited due to PECO's large number of customers and their dispersion across many industries. In 1999, PECO entered into interest rate swaps to manage interest rate exposure in the aggregate notional amount of $326 million. These swaps have been designated as cash-flow hedges under SFAS No. 133, and as such, as long as the hedge remains effective and the underlying transaction remains probable, changes in the fair value of these swaps will be recorded in accumulated other comprehensive income (loss) until earnings are affected by the variability of the cash flows being hedged. The notional amount of derivatives do not represent amounts that are exchanged by the parties and, thus, are not a measure of PECO's exposure. The amounts exchanged are calculated on the basis of the notional or contract amounts, as well as on the other terms of the derivatives, which relate to interest rates and the volatility of these rates. PECO would be exposed to credit-related losses in the event of non-performance by the counterparties that issued the derivative instruments. The credit exposure of derivatives contracts is represented by the fair value of contracts at the reporting date. PECO's interest rate swaps are documented under master agreements. Among other things, these agreements provide for a maximum credit exposure for both parties. Payments are required by the appropriate party when the maximum limit is reached. 143 On January 1, 2001, PECO deferred a non-cash gain of $40 million, net of income taxes, in accumulated other comprehensive income, a component of shareholders' equity, to reflect the initial adoption of SFAS No. 133, as amended. SFAS No. 133 is applied to all derivative instruments and requires that such instruments be recorded in the balance sheet either as an asset or a liability measured at their fair value through earnings, with special accounting permitted for certain qualifying hedges. For 2001, $6 million ($4 million, net of income taxes) was reclassified from accumulated other comprehensive income into earnings as a result of forecasted financing transactions no longer being probable. As of December 31, 2001, $15 million of deferred net gains on derivative instruments accumulated in other comprehensive income are expected to be reclassified to earnings during the next twelve months. Amounts in accumulated other comprehensive income related to interest rate cash flows are reclassified into earnings when the forecasted interest payment occurs. 18. COMMITMENTS AND CONTINGENCIES ENVIRONMENTAL ISSUES PECO's operations have in the past and may in the future require substantial capital expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, PECO is generally liable for the costs of remediating environmental contamination of property now or formerly owned by PECO and of property contaminated by hazardous substances generated by PECO. PECO owns or leases a number of real estate parcels, including parcels on which its operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. PECO has identified 28 sites where former manufactured gas plant (MGP) activities have or may have resulted in actual site contamination. PECO is currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. As of December 31, 2001 and 2000, PECO had accrued $37 million and $54 million, respectively, for environmental investigation and remediation costs, including $27 million and $30 million, respectively, for MGP investigation and remediation, that currently can be reasonably estimated. In conjunction with the corporate restructuring in January 2001, PECO transferred a portion of the environmental investigation and remediation costs to Generation. PECO cannot reasonably estimate whether it will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by PECO, environmental agencies or others, or whether such costs will be recoverable from third parties. LEASES Minimum future operating lease payments, which consist primarily of lease payments for autos, as of December 31, 2001 were: 2002 $ 2 2003 2 2004 2 2005 2 2006 2 Remaining years 3 --- Total minimum future lease payments $13 === Rental expense under operating leases totaled $2 million, $36 million, and $54 million in 2001, 2000 and 1999, respectively. 144 LITIGATION General. PECO is involved in various litigation matters. The ultimate outcome of such matters, while uncertain, is not expected to have a material adverse effect on its respective financial condition or results of operations. 19. SEGMENT INFORMATION As a result of the corporate restructuring in January 2001, PECO operates in one segment - energy delivery. Energy delivery consists of the retail electricity distribution and transmission business of PECO in southeastern Pennsylvania and the natural gas distribution business of PECO located in the Pennsylvania counties surrounding the City of Philadelphia. Prior to 2001, PECO operated in two other business segments, generation and enterprises. See Note 2 - Corporate Restructuring. Generation consisted of electric generating facilities, energy marketing operations and PECO's interests in Sithe and AmerGen. Enterprises consisted of competitive retail energy sales, energy and infrastructure services, communications and other investments weighted towards the communications, energy services and retail services industries. Prior to 2001, PECO evaluated the performance of its business segments based on Earnings Before Interest Expense and Income Taxes (EBIT). An analysis and reconciliation of PECO's business segment information to the respective information in the consolidated financial statements are as follows:

Energy Intersegment Delivery Generation Enterprises Corporate Eliminations Consolidated -------- ---------- ----------- --------- ------------ ------------ TOTAL REVENUES: 2000 $ 3,373 $2,803 $ 697 $ -- $(923) $ 5,950 1999 3,265 2,411 644 -- (842) 5,478 INTERSEGMENT REVENUES: 2000 $ 4 $ 872 $ 47 $ -- $(923) $ -- 1999 -- 842 -- -- (842) -- EBIT (a): 2000 (b) $ 1,139 $ 341 $(136) $(172) $ -- $ 1,172 1999 1,372 379 (212) (194) -- 1,345 DEPRECIATION AND AMORTIZATION: 2000 $ 195 $ 98 $ 32 $ -- $ -- $ 325 1999 108 125 4 -- -- 237 CAPITAL EXPENDITURES: 2000 $ 219 $ 243 $ 64 $ 23 $ -- $ 549 1999 205 245 1 40 -- 491 TOTAL ASSETS: 2000 $13,100 $1,648 $ 991 $(963) $ -- $14,776 1999 10,306 1,734 640 407 -- 13,087

(a) EBIT consists of operating income, equity in earnings (losses) of unconsolidated affiliates, and other income and expenses recorded in other, net with the exception of investment income. Investment income for 2000 and 1999 was $50 million and $52 million, respectively. (b) Includes non-recurring items of $248 million for Merger-related expenses in 2000. Equity in losses of communications joint ventures of $45 million and $38 million for 2000, and 1999, respectively, are included in the Enterprises business unit's EBIT. Equity in earnings of AmerGen and Sithe of $4 million for 2000 are included in the generation business unit's EBIT. 145 20. RELATED PARTY TRANSACTIONS At December 31, 2000, PECO had a $400 million payable to ComEd, which was repaid in the second quarter of 2001. The average annual interest rate on this payable for the period outstanding was 6.5%. Interest expense related to this payable for 2001 was $8 million. Effective January 1, 2001, Exelon contributed to PECO a $2.0 billion non-interest bearing receivable related to Exelon's agreement to fund future income tax payments resulting from the collection of competitive transition charges. This receivable is reflected as a reduction of Shareholders' Equity in PECO's Consolidated Balance Sheets and is expected to be settled over the years 2002 through 2010. As of December 31, 2001, the balance of this receivable from Exelon was $1.9 billion. In addition, at December 31, 2001, PECO had a $60 million payable to Exelon related to stock options in 2000. PECO paid common stock dividends of $342 million to Exelon in 2001. In connection with the transfer of the generation assets in the corporate restructuring, PECO entered into a PPA with Generation. See Note 2 - Corporate Restructuring. Intercompany power purchases pursuant to the PPA for 2001 were $1,162 million. As of December 31, 2001, PECO's payable related to the PPA was $90 million. In addition, at December 31, 2001, PECO had a $28 million payable to Generation for various services. Effective January 1, 2001, upon the corporate restructuring, PECO receives a variety of corporate support services from BSC, including legal, human resources, financial and information technology services. Such services, provided at cost including applicable overhead, were $36 million for 2001. At December 31, 2001, there was a $41 million payable to BSC. During 2001, PECO received intercompany interest income of $10 million primarily related to bills and payroll paid on behalf of BSC. PECO received services from Enterprises during 2001 for deployment of automated meters and meter reading services for $24 million. At December 31, 2001, PECO had recorded a $8 million payable to Enterprises. 21. QUARTERLY DATA (UNAUDITED) The data shown below include all adjustments which PECO considers necessary for a fair presentation of such amounts:

Income (Loss) Before Extraordinary Items and Operating Operating Cumulative Effect of a Net Revenues Income Change in Accounting Principle Income (Loss) ------------------ ---------------- ------------------------------ -------------- 2001 2000 2001 2000(a) 2001 2000 (a) 2001 2000(a) ------- ------ ---- ------- ---- -------- ----- ------- Quarter ended: March 31 $1,051 $1,352 $287 $343 $122 $166 $122 $195 June 30 $ 906 $1,385 $246 $313 $ 85 $124 $ 85 $118 September 30 $1,051 $1,629 $258 $449 $104 $238 $104 $235 December 31 $ 957 $1,584 $208 $117 $114 $(41) $114 $(41)

(a) Reflects incremental Merger expenses of $11 million, $9 million, $13 million and $215 million ($129 million, net of tax) for each of the four quarters in 2000, respectively, which were reflected in Operating and Maintenance expense. 146 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Exelon, ComEd and PECO None. 147 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Exelon The information required by Item 10 relating to directors and nominees for election as directors at Exelon's Annual Meeting of shareholders is incorporated herein by reference to the information under the heading "BOARD OF DIRECTORS" on pages 16-19 and "OTHER INFORMATION - Section 16(a) Beneficial Ownership Reporting Compliance" on page 37 in Exelon's definitive Proxy Statement (2002 Exelon Proxy Statement) filed with the SEC on March 13, 2002, pursuant to Regulation 14A under the Securities Exchange Act of 1934. The information required by Item 10 relating to executive officers is set forth above in ITEM 1. Business - Executive Officers of Exelon, ComEd and PECO. ComEd The information required by Item 10 relating to directors and nominees for election as directors at ComEd's annual meeting of shareholders is incorporated herein by reference to information under the subheadings "Nominees" and "Security Ownership of Certain Beneficial Owners and Management" under the heading "Election of Directors" in ComEd's definitive Information Statement (2002 ComEd Information Statement) to be filed with the SEC prior to April 30, 2002, pursuant to Regulation 14C under the Securities Exchange Act of 1934. The information required by Item 10 relating to executive officers is set forth above in ITEM 1. Business - Executive Officers of Exelon, ComEd and PECO. PECO The information required by Item 10 relating to directors and nominees for election as directors at PECO's annual meeting of shareholders is incorporated herein by reference to information under the subheadings "Nominees" and "Security Ownership of Certain Beneficial Owners and Management" under the heading "Election of Directors" in PECO's definitive Information Statement (2002 PECO Information Statement) to be filed with the SEC prior to April 30, 2002, pursuant to Regulation 14C under the Securities Exchange Act of 1934. The information required by Item 10 relating to executive officers is set forth above in ITEM 1. Business - Executive Officers of Exelon, ComEd and PECO. ITEM 11. EXECUTIVE COMPENSATION Exelon The information required by Item 11 is incorporated herein by reference to the information labeled "Board Compensation" and pages 13-36 in the 2002 Exelon Proxy Statement. 148 ComEd The information required by Item 11 is incorporated herein by reference to the paragraph labeled "Compensation of Directors" under the heading "Election of Directors" and the paragraphs under the heading "Executive Compensation" (other than the paragraphs under the subheading "Compensation Committee Report on Executive Compensation") in the 2002 ComEd Information Statement. PECO The information required by Item 11 is incorporated herein by reference to the paragraph labeled "Compensation of Directors" under the heading "Election of Directors" and the paragraphs under the heading "Executive Compensation" (other than the paragraphs under the subheading "Compensation Committee Report on Executive Compensation") in 2002 PECO Information Statement. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Exelon The information required by Item 12 is incorporated herein by reference to the stock ownership information under the heading "BENEFICIAL OWNERSHIP" on pages 14-15 in the 2002 Exelon Proxy Statement. ComEd The information required by Item 12 is incorporated herein by reference to the stock ownership information under the subheading "Security Ownership of Certain Beneficial Owners and Management" under the heading "Election of Directors" in the 2002 ComEd Information Statement. PECO The information required by Item 12 is incorporated herein by reference to the stock ownership information under the subheading "Security Ownership of Certain Beneficial Owners and Management" under the heading "Election of Directors" in the 2002 PECO Information Statement. 149 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Exelon The information required by Item 13 is incorporated herein by reference to the information labeled "OTHER INFORMATION - Transactions with Management" on page 37 in the 2002 Exelon Proxy Statement. ComEd The information required by Item 13 is incorporated herein by reference to the information under the subheading "Transactions with Management" under the heading "Other Information" in the 2002 ComEd Information Statement. PECO None. 150 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K REPORT OF INDEPENDENT ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULE To the Shareholders and Board of Directors of Exelon Corporation: Our audits of the consolidated financial statements referred to in our report dated January 29, 2002, except for Note 25 for which the date is March 1, 2002, appearing in the 2001 Annual Report to Shareholders of Exelon Corporation (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 14(a)(1)(ii) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. PricewaterhouseCoopers LLP Chicago, Illinois January 29, 2002 151 (a) Financial Statements and Financial Statement Schedules (1) Exelon (i) Financial Statements Consolidated Statements of Income for the years 2001, 2000 and 1999 Consolidated Statements of Cash Flows for the years 2001, 2000 and 1999 Consolidated Balance Sheets as of December 31, 2001 and 2000 Consolidated Statements of Changes in Shareholders' Equity for the years 2001, 2000 and 1999 Consolidated Statements of Comprehensive Income for the years 2001, 2000 and 1999 Notes to Consolidated Financial Statements (ii) Financial Statement Schedule 152 EXELON CORPORATION AND SUBSIDIARY COMPANIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (IN MILLIONS)

COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E -------- -------- -------- -------- -------- ADDITIONS ------------------- CHARGED BALANCE AT TO COST CHARGED BEGINNING AND TO OTHER BALANCE AT DESCRIPTION OF YEAR EXPENSES ACCOUNTS DEDUCTIONS END OF YEAR ----------- ---------- -------- -------- ---------- ----------- FOR THE YEAR ENDED DECEMBER 31, 2001 Allowance for Uncollectible Accounts $ 200 $145 $ -- $132(a) $ 213 Reserve for: Merger-Related Costs $ 144 $ -- $ 41 $ 71 $ 114 Injuries and Damages $ 69 $ 17 $ 2 $ 16(b) $ 72 Environmental Investigation and Remediation $ 171 $ 1 $ -- $ 16(c) $ 156 Obsolete Materials $ 103 $ 16 $ -- $101 $ 18 FOR THE YEAR ENDED DECEMBER 31, 2000 Allowance for Uncollectible Accounts $ 112 $ 87 $ 59(d) $ 58(a) $ 200 Reserve for: Merger-Related Costs $ -- $ -- $149(e) $ 5 $ 144 Injuries and Damages $ 23 $ 9 $ 48(f) $ 11(b) $ 69 Environmental Investigation and Remediation $ 57 $ 26 $ 98(e) $ 10(c) $ 171 Obsolete Materials $ -- $ 48 $ 55(e) $ 3 $ 100 FOR THE YEAR ENDED DECEMBER 31, 1999 Allowance for Uncollectible Accounts $ 122 $ 59 $ -- $ 69(a) $ 112 Reserve for: Injuries and Damages $ 27 $ 7 $ -- $ 11(b) $ 23 Environmental Investigation and Remediation $ 60 $ -- $ -- $ 3(c) $ 57

(a) Write-off of individual accounts receivable. (b) Payments of claims and related costs. (c) Expenditures for site investigation and remediation. (d) Includes October 20, 2000 opening balance of former Unicom Corporation of $48. (e) Reflects October 20, 2000 opening balance of former Unicom Corporation. (f) Reflects October 20, 2000 opening balance of former Unicom Corporation of $47 million. 153 (2) ComEd (i) Financial Statements Consolidated Statements of Income for the year 2001, the periods from October 20, 2000 to December 31, 2000 and from January 1, 2000 to October 19, 2000 and the year 1999 Consolidated Statements of Cash Flows for the year 2001, the periods from October 20, 2000 to December 31, 2000 and from January 1, 2000 to October 19, 2000 and the year 1999 Consolidated Balance Sheets as of December 31, 2001 and 2000 Consolidated Statements of Changes in Shareholders' Equity for the year 2001, the periods from October 20, 2000 to December 31, 2000 and from January 1, 2000 to October 19, 2000 and the year 1999 Consolidated Statements of Comprehensive Income for the year 2001, the periods from October 20, 2000 to December 31, 2000 and from January 1, 2000 to October 19, 2000 and the year 1999 Notes to Consolidated Financial Statements (ii) Financial Statement Schedule 154 COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (IN MILLIONS)

COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F -------- -------- -------- -------- -------- -------- ADDITIONS ------------------ CHARGED BALANCE AT TO COST CHARGED BEGINNING AND TO OTHER RESTRUCTURING BALANCE AT DESCRIPTION OF YEAR EXPENSES ACCOUNTS DEDUCTIONS TRANSFERS(A) END OF YEAR ----------- ------- -------- -------- ---------- ------------ ----------- FOR THE YEAR ENDED DECEMBER 31, 2001 Allowance for Uncollectible Accounts $ 60 $ 42 $ 1 $ 54 $ -- $ 49 Reserve for: Merger-Related Costs $ 144 $ -- $ 33 $ 70 $ 45 $ 62 Injuries and Damages $ 48 $ 4 $ -- $ 7(b) $ 8 $ 37 Environmental Investigation and Remediation $ 117 $ 1 $ -- $ 13(c) $ -- $ 105 Obsolete Materials $ 98 $ -- $ -- $ 14 $ 78 $ 6 FOR THE YEAR ENDED DECEMBER 31, 2000 Allowance for Uncollectible Accounts $ 49 $ 46 $ 11 $ 46 $ -- $ 60 Reserve for: Merger-Related Costs $ -- $ -- $149 $ 5 $ -- $ 144 Injuries and Damages $ 55 $ 10 $ 5 $ 22(b) $ -- $ 48 Environmental Investigation and Remediation $ 100 $ 26 $ -- $ 9(c) $ -- $ 117 Obsolete Materials $ 27 $ 57 $ 19 $ 5 $ -- $ 98 FOR THE YEAR ENDED DECEMBER 31, 1999 Allowance for Uncollectible Accounts $ 48 $ 89 $ -- $ 88 $ -- $ 49 Reserve for: Injuries and Damages $ 47 $ 28 $ 7 $ 27(b) $ -- $ 55 Environmental Investigation and Remediation $ 32 $ 74 $ -- $ 6(c) $ -- $ 100 Obsolete Materials $ 24 $ 19 $ -- $ 16 $ -- $ 27 Closing Costs for Zion Station (d) $ 79 $ -- $ -- $ 79 $ -- $ --

(a) Represents amounts transferred as part of the Corporate Restructuring. See ITEM 8. Financial Statements and Supplementary Information - ComEd, Note 2 of Notes to Consolidated Financial Statements. (b) Payments of claims and related costs. (c) Expenditures for site investigation and remediation. (d) Estimated closing costs related to the permanent cessation of nuclear generation operations and retirement of facilities at ComEd's Zion Station. 155 (3) PECO (i) Financial Statements Consolidated Statements of Income for the years 2001, 2000 and 1999 Consolidated Statements of Cash Flows for the years 2001, 2000 and 1999 Consolidated Balance Sheets as of December 31, 2001 and 2000 Consolidated Statements of Changes in Shareholders' Equity for the years 2001, 2000 and 1999 Consolidated Statements of Comprehensive Income for the years 2001, 2000 and 1999 Notes to Consolidated Financial Statements (ii) Financial Statement Schedule 156 PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (IN MILLIONS)

COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F -------- -------- -------- -------- -------- -------- ADDITIONS ------------------- CHARGED BALANCE AT TO COST CHARGED BEGINNING AND TO OTHER RESTRUCTURING BALANCE AT DESCRIPTION OF YEAR EXPENSES ACCOUNTS DEDUCTIONS TRANSFERS(A) END OF YEAR ----------- ---------- -------- -------- ---------- ------------- ----------- FOR THE YEAR ENDED DECEMBER 31, 2001 Allowance for Uncollectible Accounts $131 $ 69 $-- $ 67(b) $23 $110 Reserve for: Injuries and Damages $ 21 $ 13 $-- $ 9(c) $-- $ 25 Environmental Investigation and Remediation $ 54 $-- $-- $ 2(d) $15 $ 37 Obsolete Materials $ 3 $ 6 $-- $ 7 $ 1 $ 1 FOR THE YEAR ENDED DECEMBER 31, 2000 Allowance for Uncollectible Accounts $112 $ 68 $-- $ 49(b) $-- $131 Reserve for: Injuries and Damages $ 23 $ 7 $-- $ 9(c) $-- $ 21 Environmental Investigation and Remediation $ 57 $-- $-- $ 3(d) $-- $ 54 FOR THE YEAR ENDED DECEMBER 31, 1999 Allowance for Uncollectible Accounts $122 $ 59 $-- $ 69(b) $-- $112 Reserve for: Injuries and Damages $ 27 $ 7 $-- $ 11(c) $-- $ 23 Environmental Investigation and Remediation $ 60 $-- $-- $ 3(d) $-- $ 57

(a) Represents amounts transferred as part of the Corporate Restructuring. See ITEM 8. Financial Statements and Supplementary Information - ComEd, Note 2 of the Notes to Consolidated Financial Statements. (b) Write-off of individual accounts receivable. (c) Payments of claims and related costs. (d) Expenditures for site investigation and remediation. 157 The individual financial statements and schedules of Exelon's and ComEd's nonconsolidated wholly owned subsidiaries have been omitted from their respective Annual Reports on Form 10-K because the investments are not material in relation to their respective financial positions or results of operations. As of December 31, 2001, the assets of the nonconsolidated subsidiaries, in the aggregate, were less than 1% of Exelon's and ComEd's consolidated assets. The 2001 revenues of the nonconsolidated subsidiaries, in the aggregate, were less than 1% of Exelon's and ComEd's consolidated annual revenues. (b) Reports on Form 8-K (1) Exelon Exelon filed Current Reports on Form 8-K during the fourth quarter of 2001 regarding the following items:

Date of Earliest Event Reported Description of Item Reported -------------- ---------------------------- October 23, 2001 "ITEM 5. OTHER EVENTS" regarding Exelon's earnings release for the third quarter of 2001. October 23, 2001 "ITEM 9. REGULATION FD DISCLOSURE" regarding highlights and clarifications of the Exelon Third Quarter Earnings Conference Call. October 29, 2001 "ITEM 9. REGULATION FD DISCLOSURE" regarding a presentation by John W. Rowe, Co-CEO and President of Exelon, at the Edison Electric Institute Conference. The exhibits under "ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS" include the slide presentation and additional information. November 28, 2001 "ITEM 9. REGULATION FD DISCLOSURE" regarding a press release issued by Exelon disclosing its direct net exposure to Enron. December 20, 2001 "ITEM 5. OTHER EVENTS" regarding the announcement by Exelon of its intention to purchase two generating plants from TXU Corp. and "ITEM 9. REGULATION FD DISCLOSURE" regarding additional information related to the acquisition.

158 (2) ComEd ComEd filed Current Reports on Form 8-K during the fourth quarter of 2001 regarding the following items:

Date of Earliest Event Reported Description of Item Reported -------------- ---------------------------- October 23, 2001 "ITEM 5. OTHER EVENTS" regarding Exelon's earnings release for the third quarter of 2001. October 23, 2001 "ITEM 9. REGULATION FD DISCLOSURE" regarding highlights and clarifications of the Exelon Third Quarter Earnings Conference Call. October 29, 2001 "ITEM 9. REGULATION FD DISCLOSURE" regarding a presentation by John W. Rowe, Co-CEO and President of Exelon, at the Edison Electric Institute Conference. The exhibits under "ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS" include the slide presentation and additional information.

(3) PECO PECO filed Current Reports on Form 8-K during the fourth quarter of 2001 regarding the following items:

Date of Earliest Event Reported Description of Item Reported -------------- ---------------------------- October 23, 2001 "ITEM 5. OTHER EVENTS" regarding Exelon's earnings release for the third quarter of 2001. October 23, 2001 "ITEM 9. REGULATION FD DISCLOSURE" regarding highlights and clarifications of the Exelon Third Quarter Earnings Conference Call. October 29, 2001 "ITEM 9. REGULATION FD DISCLOSURE" regarding a presentation by John W. Rowe, Co-CEO and President of Exelon, at the Edison Electric Institute Conference. The exhibits under "ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS" include the slide presentation and additional information. October 30, 2001 "ITEM 5. OTHER EVENTS" regarding the issuance of a press release announcing the sale of $250 million of PECO first mortgage bonds through private placement.

159 (c) Exhibits Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis and the relevant registrant agrees to furnish a copy of any such instrument to the Commission upon request.

Exhibit No. Description ----------- ----------- 2-1 Amended and Restated Agreement and Plan of Merger dated as of October 20, 2000, among PECO Energy Company, Exelon Corporation and Unicom Corporation (File No. 1-01401, PECO Energy Company Form 10-Q for the quarter ended September 30, 2000, Exhibit 2-1) 3-1 Articles of Incorporation of Exelon Corporation (Registration Statement No. 333-37082, Form S-4, Exhibit 3-1). 3-2 Bylaws of Exelon Corporation (Registration Statement No. 333-37082, Form S-4, Exhibit 3-2). 3-3 Amended and Restated Articles of Incorporation of PECO Energy Company (File No. 1-1401, 2000 Form 10-K, Exhibit 3-3). 3-4 Bylaws of PECO Energy Company, adopted February 26, 1990 and amended January 26, 1998 (File No. 1-01401, 1997 Form 10-K, Exhibit 3-2). 3-5 Restated Articles of Incorporation of Commonwealth Edison Company effective February 20, 1985, including Statements of Resolution Establishing Series, relating to the establishment of three new series of Commonwealth Edison Company preference stock known as the "$9.00 Cumulative Preference Stock," the "$6.875 Cumulative Preference Stock" and the "$2.425 Cumulative Preference Stock" (File No. 1-1839, 1994 Form 10-K, Exhibit 3-2). 3-6 Bylaws of Commonwealth Edison Company, effective September 2, 1998, as amended through October 20, 2000 (File No. 1-1839, 2000 Form 10-K, Exhibit 3-6). 4-1 364-day Credit Agreement, dated as of December 12, 2001, among Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation, LLC as Borrowers, certain banks named therein as Lenders, Bank One, N.A., as Administrative Agent, ABN AMRO Bank, N.V. and Barclays Bank plc, as Co-documentation Agents, Citibank, N.A. and First Union National Bank, as Co-syndication Agents and Banc One Capital Markets, Inc., as Lead Arranger and Sole Book Runner. 4-2 First and Refunding Mortgage dated May 1, 1923 between The Counties Gas and Electric Company (predecessor to PECO Energy Company) and Fidelity Trust Company, Trustee (First Union National Bank, successor), (Registration No. 2-2281, Exhibit B-1). 4-2-1 Supplemental Indentures to PECO Energy Company's First and Refunding Mortgage:

160

Dated as of File Reference Exhibit No. ----------- -------------- ----------- May 1, 1927 2-2881 B-1(c) March 1, 1937 2-2881 B-1(g) December 1, 1941 2-4863 B-1(h) November 1, 1944 2-5472 B-1(i) December 1, 1946 2-6821 7-1(j) September 1, 1957 2-13562 2(b)-17 May 1, 1958 2-14020 2(b)-18 March 1, 1968 2-34051 2(b)-24 March 1, 1981 2-72802 4-46 March 1, 1981 2-72802 4-47 December 1, 1984 1-01401, 1984 Form 10-K 4-2(b) April 1, 1991 1-01401, 1991 Form 10-K 4(e)-76 December 1, 1991 1-01401, 1991 Form 10-K 4(e)-77 April 1, 1992 1-01401, March 31, 1992 Form 10-Q 4(e)-79 June 1, 1992 1-01401, June 30, 1992 Form 10-Q 4(e)-81 July 15, 1992 1-01401, June 30, 1992 Form 10-Q 4(e)-83 September 1, 1992 1-01401, 1992 Form 10-K 4(e)-85 March 1, 1993 1-01401, 1992 Form 10-K 4(e)-86 May 1, 1993 1-01401, March 31, 1993 Form 10-Q 4(e)-88 May 1, 1993 1-01401, March 31, 1993 Form 10-Q 4(e)-89 August 15, 1993 1-01401, Form 8-A dated August 19, 1993 4(e)-92 May 1, 1995 1-01401, Form 8-K dated 4(e)-96 May 24, 1995 October 15, 2001

4-3 Exelon Corporation Dividend Reinvestment and Stock Purchase Plan. (Registration Statement No. 333-84446, Form S-3, Prospectus) 4-4 Mortgage of Commonwealth Edison Company to Illinois Merchants Trust Company, Trustee (BNY Midwest Trust Company, as current successor Trustee), dated July 1, 1923, as supplemented and amended by Supplemental Indenture thereto dated August 1, 1944. (File No. 2-60201, Form S-7, Exhibit 2-1). 4-3 Exelon Corporation Dividend Reinvestment and Stock Purchase Plan. (Registration Statement No. 333-84446, Form S-3, Prospectus) 4-4 Mortgage of Commonwealth Edison Company to Illinois Merchants Trust Company, Trustee (BNY Midwest Trust Company, as current successor Trustee), dated July 1, 1923, as supplemented and amended by Supplemental Indenture thereto dated August 1, 1944. (File No. 2-60201, Form S-7, Exhibit 2-1). 161 4-4-1 Supplemental Indentures to aforementioned Commonwealth Edison Mortgage.

Dated as of File Reference Exhibit No. ----------- -------------- ----------- August 1, 1946 2-60201, Form S-7 2-1 April 1, 1953 2-60201, Form S-7 2-1 March 31, 1967 2-60201, Form S-7 2-1 April 1,1967 2-60201, Form S-7 2-1 February 28, 1969 2-60201, Form S-7 2-1 May 29, 1970 2-60201, Form S-7 2-1 June 1, 1971 2-60201, Form S-7 2-1 April 1, 1972 2-60201, Form S-7 2-1 May 31, 1972 2-60201, Form S-7 2-1 June 15, 1973 2-60201, Form S-7 2-1 May 31, 1974 2-60201, Form S-7 2-1 June 13, 1975 2-60201, Form S-7 2-1 May 28, 1976 2-60201, Form S-7 2-1 June 3, 1977 2-60201, Form S-7 2-1 May 17, 1978 2-99665, Form S-3 4-3 August 31, 1978 2-99665, Form S-3 4-3 June 18, 1979 2-99665, Form S-3 4-3 June 20, 1980 2-99665, Form S-3 4-3 April 16, 1981 2-99665, Form S-3 4-3 April 30, 1982 2-99665, Form S-3 4-3 April 15, 1983 2-99665, Form S-3 4-3 April 13, 1984 2-99665, Form S-3 4-3 April 15, 1985 2-99665, Form S-3 4-3 April 15, 1986 33-6879, Form S-3 4-9 June 15, 1990 33-38232, Form S-3 4-12 June 1, 1991 33-40018, Form S-3 4-12 October 1, 1991 33-40018, Form S-3 4-13 October 15, 1991 33-40018, Form S-3 4-14 February 1, 1992 1-1839, 1991 Form 10-K 4-18 May 15, 1992 33-48542, Form S-3 4-14 July 15, 1992 33-53766, Form S-3 4-13 September 15, 1992 33-53766, Form S-3 4-14 February 1, 1993 1-1839, 1992 Form 10-K 4-14 April 1, 1993 33-64028, Form S-3 4-12 April 15, 1993 33-64028, Form S-3 4-13 June 15, 1993 1-1839, Form 8-K dated May 4-1 July 15, 1993 1-1839, Form 10-Q for 4-1 quarter ended June 30, 1993. January 15, 1994 1-1839, 1993 Form 10-K 4-15 December 1, 1994 1-1839, 1994 Form 10-K 4-16 June 1, 1996 1-1839, 1996 Form 10-K 4-16 March 1, 2002

162 4-4-2 Instrument of Resignation, Appointment and Acceptance dated as of February 20, 2002, under the provisions of the Mortgage dated July 1, 1923, and Indentures Supplemental thereto, regarding corporate trustee. 4-4-3 Instrument dated as of January 31, 1996, under the provisions of the Mortgage dated July 1, 1923 and Indentures Supplemental thereto, regarding individual trustee (File No. 1-1839, 1995 Form 10-K, Exhibit 4-29). 4-5 Indenture dated as of September 1, 1987 between Commonwealth Edison Company and Citibank, N.A., Trustee relating to Notes (File No. 1-1839, Form S-3, Exhibit 4-13). 4-6-1 Supplemental Indentures to aforementioned Indenture.

Dated as of File Reference Exhibit No. ----------- -------------- ----------- September 1, 1987 33-32929, Form S-3 4-16 January 1, 1997 1-1839, 1999 Form 10-K 4-21 September 1, 2000 1-1839, 2000 Form 10-K 4-7-3

10-1 Stock Purchase Agreement among Exelon (Fossil) Holdings, Inc., as Buyer and The Stockholders of Sithe Energies, Inc., as Sellers, and Sithe Energies, Inc. (File No. 0-16844, PECO Energy Company Form 10-Q for the quarter ended September 30, 2000, Exhibit 10-1). 10-2 Amended and restated employment agreement between Exelon Corporation and John W. Rowe dated as of November 26, 2001.* 10-3 Exelon Corporation Deferred Compensation Pension Benefit Plan* 10-4 Exelon Corporation Retirement Program 10-5 PECO Energy Company Unfunded Deferred Compensation Plan for Directors* (Registration Statement No. 333-49780, Form S-8, Exhibit 4-4). 10-6 Exelon Corporation Long-Term Incentive Plan As Amended and Restated effective January 28, 2002 * (File No. 1-16169, Exelon Proxy Statement dated March 13, 2002, Appendix B). 10-6-1 Forms of Restricted Stock Award Agreement under the Exelon Corporation Long-Term Incentive Plan.* 10-6-2 Forms of Transferable Stock Option Award Agreement under the Exelon Corporation Long-Term Incentive Plan.* 10-6-3 Forms of non-transferable Stock Option Award Agreement under the Exelon Corporation Long-Term Incentive Plan* 10-7 PECO Energy Company Management Incentive Compensation Plan *(File No. 1-01401, 1997 Proxy Statement, Appendix A). 10-8 PECO Energy Company 1998 Stock Option Plan *(Registration Statement No. 333-37082, Post-Effective Amendment No. 1 to Form S-4, Exhibit 4-3). 10-9 Exelon Corporation Employee Savings Plan 163 10-10 Second Amended and Restated Trust Agreement for PECO Energy Transition Trust (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated May 2, 2000, Exhibit 4.1). 10-11 Indenture dated as of March 1, 1999 between PECO Energy Transition Trust and The Bank of New York. (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated March 25, 1999, Exhibit 4.3.1). 10-11-1 Series Supplement dated as of March 25, 1999 between PECO Energy Transition Trust and The Bank of New York. (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated March 25, 1999, Exhibit 4.3.2). 10-11-2 Series Supplement dated as of March 1, 2001 between PECO Energy Transition Trust and The Bank of New York. (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated March 1, 2001, Exhibit 4.3.2). 10-11-3 Series Supplement dated as of May 2, 2000 between PECO Energy Transition Trust and The Bank of New York (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated May 2, 2000, Exhibit 4.3.2). 10-12 Intangible Transition Property Sale Agreement dated as of March 25,1999, as amended and restated as of May 2, 2000, between PECO Energy Transition Trust and PECO Energy Company. (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated May 2, 2000, Exhibit 10.1). 10-12-1 Amendment No. 1 to Intangible Transition Property Sale Agreement dated as of March 25, 1999, as amended and restated as of May 2, 2000 (File No. 1-01401, PECO Energy Company and PECO Energy Transition Trust Report on Form 8-K dated March 1, 2001). 10-13 Master Servicing Agreement dated as of March 25, 1999, as amended and restated as of May 2, 2000, between PECO Energy Transition Trust and PECO Energy Company. (File No. 333-58055, PECO Energy Transition Trust Current Report on Form 8-K dated May 2, 2000, Exhibit 10.2). 10-13-1 Amendment No. 1 to Master Servicing Agreement dated as of March 25, 1999, as amended and restated as of May 2, 2000 (File No. 1-01401, PECO Energy Company and PECO Energy Transition Trust Report on Form 8-K dated March 1, 2001). 10-14 Exelon Corporation Cash Balance Pension Plan 164 10-15 Joint Petition for Full Settlement of PECO Energy Company's Restructuring Plan and Related Appeals and Application for a Qualified Rate Order and Application for Transfer of Generation Assets dated April 29, 1998. (Registration Statement No. 333-58055, Exhibit 10.3). 10-16 Joint Petition for Full Settlement of PECO Energy Company's Application for Issuance of Qualified Rate Order Under Section 2812 of the Public Utility Code dated March 8, 2000 (Amendment No. 1 to Registration Statement No. 333-31646, Exhibit 10.4). 10-17 Unicom Corporation Amended and Restated Long-Term Incentive Plan *(File No. 1-11375, Unicom Proxy Statement dated April 7, 1999, Exhibit A). 10-17-1 First Amendment to Unicom Corporation Amended and Restated Long Term Incentive Plan *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-8). 10-17-2 Second Amendment to Unicom Corporation Amended and Restated Long Term Incentive Plan *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-9). 10-18 Unicom Corporation General Provisions Regarding 1996 Stock Option Awards Granted under the Unicom Corporation and Long-Term Incentive Plan. *(File Nos. 1-11375 and 1-1839, 1996 Form 10-K, Exhibit 10-9). 10-19 Unicom Corporation General Provisions Regarding 1996B Stock Option Awards Granted under the Unicom Corporation Long-Term Incentive Plan. *(File Nos. 1-11375 and 1-1839, 1996 Form 10-K, Exhibit 10-8). 10-20 Unicom Corporation General Provisions Regarding Stock Option Awards Granted under the Unicom Corporation Long-Term Incentive Plan (Effective July 10, 1997) *(File Nos. 1-11375 and 1-1839, 1999 Form 10-K, Exhibit 10-8). 10-21 Unicom Corporation Deferred Compensation Unit Plan, as amended *(File Nos. 1-11375 and 1-1839, 1995 Form 10-K, Exhibit 10-12). 10-22 Exelon Corporation Corporate Stock Referral Plan* 10-23 Unicom Corporation Retirement Plan for Directors, as amended *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-12). 10-24 Commonwealth Edison Company Retirement Plan for Directors, as amended *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-13). 10-25 Unicom Corporation 1996 Directors' Fee Plan *(File No. 1-11375, Unicom Proxy Statement dated April 8, 1996, Appendix A). 165 10-25-1 Second Amendment to Unicom Corporation 1996 Directors Fee Plan *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-11). 10-26 Employment Agreement dated November 1, 1997 between Commonwealth Edison Company and Oliver D. Kingsley, Jr. (File Nos. 1-11375 and 1-1839, 1998 Form 10-K, Exhibit 10-22). 10-27 Change in Control Agreement between Unicom Corporation, Commonwealth Edison Company and certain senior executives *(File Nos. 1-11375 and 1-1839, 1998 Form 10-K, Exhibit 10-24). 10-27-1 Forms of Change in Control Agreement Between PECO Energy Company and Certain Employees *(File No. 1-1401, 2000 Form 10-K, Exhibit 10-25-1). 10-28 Commonwealth Edison Company Executive Group Life Insurance Plan *(File No. 1-1839, 1980 Form 10-K, Exhibit 10-3). 10-28-1 Amendment to the Commonwealth Edison Company Executive Group Life Insurance Plan *(File No. 1-1839, 1981 Form 10K, Exhibit 10-4). 10-28-2 Amendment to the Commonwealth Edison Company Executive Group Life Insurance Plan dated December 12, 1986 *(File No. 1-1839, 1986 Form 10-K, Exhibit 10-6). 10-28-3 Amendment to the Commonwealth Edison Company Executive Group Life Insurance Plan to implement program of "split dollar life insurance" dated December 13, 1990 *(File No. 1-1839, 1990 Form 10-K, Exhibit 10-10). 10-28-4 Amendment to Commonwealth Edison Company Executive Group Life Insurance Plan to stabilize the death benefit applicable to participants dated July 22, 1992 *(File No. 1-1839, 1992 Form 10-K, Exhibit 10-13). 10-29 First Amendment to Exelon Corporation Employee Savings Plan 10-29-1 First Amendment to the Commonwealth Edison Company Supplemental Management Retirement Plan. *(File No. 1-1839, 2000 Form 10-K, Exhibit 10-27-1) 10-30 Second Amendment and Restated Exelon Corporation Key Management Severance Plan* 10-31 Forms of Change in Control Agreement between Exelon Corporation and Certain Senior Executives. 166 10-32 Amendment No. 1 to Exelon Corporation Supplemental Executive Retirement Plan* 10-33 Form of Stock Award Agreement under the Unicom Corporation Long-Term Incentive Plan *(File Nos. 1-11375 and 1-1839, 1997 Form 10-K, Exhibit 10-37). 10-34 Amended and Restated Key Management Severance Plan for Unicom Corporation and Commonwealth Edison Company dated March 8, 1999 *(File No. 1-1839, 1999 Form 10-K, Exhibit 10-38). 10-34-1 Exelon Corporation Employee Stock Purchase Plan (Registration Statement No. 333-61390, Form S-8, Exhibit 4.2). 10-34-2 First Amendment to the Exelon Corporation Employee Stock Purchase Plan. 10-35 PECO Energy Company Supplemental Pension Benefit Plan (As Amended and Restated January 1, 2001)* 10-36 Exelon Corporation 2001 Performance Share Awards for Power Team Employees Under the Exelon Corporation Long Term Incentive Plan* 16 Arthur Andersen Letter to Securities and Exchange Commission regarding the change in certifying accountant (File No. 1-01839, Exelon Corporation Report on Form 8-K dated November 28, 2000, Exhibit 16). 18-1 Letter from PricewaterhouseCoopers LLP addressed to Exelon Corporation concerning a change in accounting principles (File No. 1-16169, 2000 Form 10-K, Exhibit 18-1). 18-2 Letter from PricewaterhouseCoopers LLP addressed to PECO Energy Company concerning a change in accounting principles (File No. 1-1401, 2000 Form 10-K, Exhibit 10-30-1). 21 Subsidiaries 21-1 Exelon Corporation 21-2 Commonwealth Edison Company (File No. 1-1839, 2000 Form 10-K, Exhibit 21-3). 21-3 PECO Energy Company (File No. 1-1401, 2000 Form 10-K, Exhibit 21-2). 167 23 Consent of Independent Accountants 23-1 Exelon Corporation 23-2-1 Commonwealth Edison Company 23-2-2 Commonwealth Edison Company 23-3 PECO Energy Company 99 Exelon Corporation's Current Report on Form 8-K dated February 28, 2002, File No. 1-16169. ------------------------------------------------------------------------------- * Compensatory plan or arrangements in which directors or officers of the applicable registrant participate and which are not available to all employees. 168 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 1st day of April, 2002. EXELON CORPORATION By: /S/ Corbin A. McNeill, Jr. ------------------------------- Name: Corbin A. McNeill, Jr. Title: Chairman and Co-Chief Executive Officer By: /S/ John W. Rowe ------------------------------- Name: John W. Rowe Title: President and Co-Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on the 1st day of April, 2002.

Signature Title --------- ----- /S/ Corbin A. McNeill, Jr. Chairman and Co-Chief Executive Officer and Director --------------------------- Corbin A. McNeill, Jr. (Co-Chief Executive Officer) /S/ John W. Rowe President and Co-Chief Executive Officer and Director --------------------------- John W. Rowe (Co-Chief Executive Officer) /S/ Ruth Ann M. Gillis Senior Vice President and Chief Financial Officer --------------------------- Ruth Ann M. Gillis (Principal Financial and Accounting Officer)

This annual report has also been signed below by John W. Rowe and Randall E. Mehrberg, Attorneys-in-Fact, on behalf of the following Directors on the date indicated: EDWARD A. BRENNAN RICHARD H. GLANTON CARLOS H. CANTU ROSEMARIE B. GRECO DANIEL L. COOPER EDGAR D. JANNOTTA M. WALTER D'ALESSIO JOHN M. PALMS, PH.D. BRUCE DEMARS JOHN W. ROGERS, JR. G. FRED DIBONA, JR. RONALD RUBIN SUE L. GIN RICHARD L. THOMAS By: /S/ John W. Rowe April 1, 2002 ------------------------------------------------- Name: John W. Rowe Title: President and Co-Chief Executive Officer By: /S/ Randall E. Mehrberg April 1, 2002 ------------------------------------------------- Name: Randall E. Mehrberg Title: Senior Vice President and General Counsel 169 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 1st day of April, 2002. COMMONWEALTH EDISON COMPANY By: /S/ John W. Rowe ------------------------------ Name: John W. Rowe Title: President, Co-Chief Executive Officer and Chairman By: /S/ Corbin A. McNeill, Jr. ------------------------------- Name: Corbin A. McNeill, Jr. Title: Co-Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on the 1st day of April, 2002.

Signature Title --------- ----- /S/ John W. Rowe President, Co-Chief Executive Officer and Chairman --------------------------- John W. Rowe /S/ Corbin A. McNeill, Jr. Co-Chief Executive Officer --------------------------- Corbin A. McNeill, Jr. /S/ Robert E. Berdelle Vice President and Chief Financial Officer --------------------------- Robert E. Berdelle (Principal Financial and Accounting Officer) /S/ Pamela B. Strobel Chairman --------------------------- Pamela B. Strobel (Principal Executive Officer) /S/ Ruth Ann M. Gillis Director --------------------------- Ruth Ann M. Gillis /S/ Kenneth G. Lawrence Director --------------------------- Kenneth G. Lawrence

170 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 1st day of April, 2002. PECO ENERGY COMPANY By: /S/ Corbin A. McNeill, Jr. ------------------------------- Name: Corbin A. McNeill, Jr. Title: President, Co-Chief Executive Officer and Chairman By: /S/ John W. Rowe ------------------------------- Name: John W. Rowe Title: Co-Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on the 1st day of April, 2002.

Signature Title --------- ----- /S/ Corbin A. McNeill, Jr. President, Co-Chief Executive Officer and Chairman --------------------------- Corbin A. McNeill, Jr. /S/ John W. Rowe Co-Chief Executive Officer --------------------------- John W. Rowe /S/ Frank F. Frankowski Vice President, Finance and Chief Financial Officer --------------------------- Frank F. Frankowski (Principal Financial and Accounting Officer) /S/ Pamela B. Strobel Chairman --------------------------- Pamela B. Strobel (Principal Executive Officer) /S/ Ruth Ann M. Gillis Director --------------------------- Ruth Ann M. Gillis /S/ Kenneth G. Lawrence Director --------------------------- Kenneth G. Lawrence

171