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

FORM 10-K

ý   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2002

OR

o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File
Number
 
Name of Registrant; State of Incorporation; Address of
Principal Executive Offices; and Telephone Number
 
IRS Employer
Identification Number
1-16169   EXELON CORPORATION
(a Pennsylvania corporation)
10 South Dearborn Street — 37th Floor
P.O. Box 805379
Chicago, Illinois 60680-5379
(312) 394-7398		   23-2990190

1-1839
 
COMMONWEALTH EDISON COMPANY
(an Illinois corporation)
10 South Dearborn Street — 37th Floor
P.O. Box 805379
Chicago, Illinois 60680-5379
(312) 394-4321
 
36-0938600

1-1401
 
PECO ENERGY COMPANY
(a Pennsylvania corporation)
P.O. Box 8699
2301 Market Street
Philadelphia, Pennsylvania 19101-8699
(215) 841-4000
 
23-0970240

333-85496
 
EXELON GENERATION COMPANY, LLC
(a Pennsylvania limited liability company)
300 Exelon Way
Kennett Square, Pennsylvania 19348
(610) 765-6900
 
23-3064219

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

Title of Each Class
   Name of Each
Exchange on Which Registered
EXELON CORPORATION:    
Common Stock, without par value   New York, Chicago and Philadelphia

COMMONWEALTH EDISON COMPANY:
 
 
Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Commonwealth Edison Company's 8.48% Subordinated Debt Securities and unconditionally guaranteed by Commonwealth Edison Company   New York

PECO ENERGY COMPANY:
 
 
First and Refunding Mortgage Bonds: 63/8% Series due 2005, and 61/2% Series due 2003   New York
Cumulative Preferred Stock, without par value: $4.68 Series, $4.40 Series, $4.30 Series and $3.80 Series   New York

Trust Receipts of PECO Energy Capital Trust II, each representing an 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
 
New York
Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company   New York

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

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

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

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

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

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

Exelon Corporation   Yes ý   No o
Commonwealth Edison Company   Yes o   No ý
PECO Energy Company   Yes o   No ý
Exelon Generation Company, LLC   Yes o   No ý

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

Exelon Corporation Common Stock, without par value   $16,886,511,503
Commonwealth Edison Company Common Stock, $12.50 par value   No established market
PECO Energy Company Common Stock, without par value   None
Exelon Generation Company, LLC   Not applicable

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

Exelon Corporation Common Stock, without par value   324,068,637
Commonwealth Edison Company Common Stock, $12.50 par value   127,016,425
PECO Energy Company Common Stock, without par value   170,478,507
Exelon Generation Company, LLC   Not applicable

Other

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

DOCUMENTS INCORPORATED BY REFERENCE:

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

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

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

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


TABLE OF CONTENTS

 
    
   Page No.
FORWARD-LOOKING STATEMENTS   1
WHERE TO FIND MORE INFORMATION   1

PART I
 
 
ITEM 1.   BUSINESS   2
            General   2
            Energy Delivery   3
            Generation   14
            Enterprises   32
            Employees   33
            Environmental Regulation   33
            Other Subsidiaries of ComEd and PECO with Publicly Held Securities   37
            Executive Officers of the Registrants   39
ITEM 2.   PROPERTIES   42
ITEM 3.   LEGAL PROCEEDINGS   44
ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS   47

PART II
 
 
ITEM 5.   MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS   48
ITEM 6.   SELECTED FINANCIAL DATA   49
ITEM 7.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   53
ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK   132
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA   144
ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE   256

PART III
 
 
ITEM 10.   DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT   257
ITEM 11.   EXECUTIVE COMPENSATION   257
ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS   258
ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS   258
ITEM 14.   CONTROLS AND PROCEDURES   259

PART IV
 
 
ITEM 15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K   262

SIGNATURES
 
280
CERTIFICATIONS   284


FORWARD-LOOKING STATEMENTS

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


WHERE TO FIND MORE INFORMATION

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

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

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

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

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

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

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

Energy Delivery

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

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

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

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

3

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

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

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

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

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

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

Retail Electric Services

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

4

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

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

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

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

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

5

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

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

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

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

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

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

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

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

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

7

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

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

        The Agreement addresses, among other things:

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

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

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

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

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

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

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

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

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

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

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

 
   Allowed Recovery,
Excluding Gross
Receipts Tax
Year
  Total
   Return @ 10.75%
   Amortization
 
   ($000)


   ($000)


   ($000)
2003   818,352   482,401   335,951
2004   811,540   444,798   366,742
2005   807,933   403,555   404,378
2006   902,623   353,070   549,553
2007   909,844   290,627   619,217
2008   917,123   220,312   696,811
2009   924,459   141,229   783,231
2010   931,855   52,381   879,474

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

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

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

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

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

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

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

Transmission Services

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

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

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

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

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

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

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

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

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

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

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Gas

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

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

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

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

Construction Budget

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

 
   ComEd
   PECO
 
   (in millions)
Transmission and Distribution   $ 634   $ 201
Gas     —     60
Other     86     9
   
 
Total   $ 720   $ 270
   
 

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

Generation

General

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

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

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

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

Generating Resources

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

Type of Capacity
   MW
Owned Generation Assets(1,2)    
  Nuclear   14,547
  Fossil   8,210
  Hydro   1,584
   
    24,341
Long-term Contracts(3)   13,900
AmerGen and Sithe(2)   1,900
   
    Available Resources   40,141
Under Construction(2)   2,536
   
    Total Generating Resources   42,677
   
(1)
See ITEM 1. Business—Generation "Fuel" for sources of fuels used in electric generation.

(2)
Based on Generation's percentage ownership.

(3)
Contracts range from 1 to 29 years.

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

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

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

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

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

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

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

        Licenses.    Exelon has 40-year operating licenses from the NRC for each of its nuclear units. Generation applied to the NRC in July 2001 for renewal of the Peach Bottom units 2 and 3 licenses and has applied for the extension of the operating license for Dresden units 2 and 3 and Quad Cities Station in January 2003. The operating license renewal process takes approximately four to five years from the commencement of the project at a site until completion of the NRC's review. The NRC review process takes approximately two years from the docketing of an application. Each requested license extension is expected to be for 20 years beyond the current license expiration. Depreciation provisions are based on the estimated useful lives of the units, which assume the extension of these

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

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

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

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

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

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

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

17


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

        Fossil units include:

        Hydroelectric facilities include:

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

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

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

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

        Licenses.    Fossil generation plants are generally not licensed and, therefore, the decision on when to retire plants is, fundamentally, an economic one. Hydroelectric plants are licensed by FERC. The Muddy Run and Conowingo facilities have licenses that expire in September 2014. Generation is considering applying to FERC for license extensions of 40 years for both plants, but the duration of any license extension will depend on then-current policies at FERC. The process of applying for an extension to an existing hydroelectric license generally takes at least eight years.

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

Long-Term Contracts

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

Seller
   Location
   Expiration
   Capacity (MW)
Midwest Generation, LLC   Various in Illinois   2004   4,879
Kincaid Generation, LLC   Kincaid, Illinois   2013   1,158
Tenaska Georgia Partners, LP   Franklin, Georgia   2030   925
Tenaska Frontier, Ltd   Shiro, Texas   2020   830
Others   Various   2004 to 2022   6,108
           
Total           13,900
           

        Midwest Generation, LLC Contract.    Generation is a party to contracts with Midwest Generation, LLC (Midwest Generation), a subsidiary of Edison Mission Energy. Under the contracts, Generation initially had the right to purchase through 2004 the capacity and energy associated with approximately 9,460 MW of fossil-fired generation stations located in Northern Illinois, formerly owned by ComEd. The generation units include base-load, intermediate and peaking units. Under the contracts, Generation pays a fixed capacity charge that varies by season and a fixed energy charge. The capacity charge is reduced to the extent the plants are unable to generate and deliver energy when requested. Under the contracts, Generation has annual rights to reduce the capacity and related energy purchase obligations, and some of these rights were recently exercised. On January 1, 2002, Generation released all of the 355 MW of oil-fixed peaking capacity that is covered by the contracts. On July 1, 2002, Generation elected to exercise its call option on 1,265 MWs of capacity for 2003. Generation has a total of 4,879 MWs of capacity under the Coal, Collins Generating Station (Collins) and Peaking Unit (Peaking) PPAs, of which Generation retains 1,918 MWs of option capacity under the Collins and Peaking PPAs as well as 1,265 MWs of option capacity under the Coal Generation PPA. Generation will decide whether to exercise its options in 2003, effective January 1, 2004, depending on the projected need for capacity and energy to fulfill obligations under the agreement with ComEd or otherwise, taking into account forward market conditions and other alternatives. On October 2, 2002, Generation notified Midwest Generation of its exercise of termination options under the existing Collins and Peaking Unit (Peaking) PPAs. Generation exercised its termination options on 1,727 MWs in 2003 and 2004. In 2003, Generation will take 1,778 MWs of option capacity under the Collins and Peaking Unit Agreements as well as 1,265 MWs of option capacity under the Coal Generation PPA.

Federal Power Act

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

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

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

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

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

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

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

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

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

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

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

Fuel

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

 
   Source of Electric Supply
 
   2002
   2003 (Est.)
Nuclear units(1)   115,854   119,733
Purchases—non-trading portfolio(2)   78,710   61,271
Fossil and hydro units   12,976   11,326
   
 
Total Supply   207,540   192,330
   
 
(1)
Excluding AmerGen.

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(2)
Including PPAs with AmerGen.

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

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

        Generation obtains approximately 25% of its uranium enrichment services from European suppliers. There is an ongoing trade action by USEC, Inc. (USEC) alleging dumping in the United States against European enrichment services suppliers. In January 2002, the U.S. International Trade Commission determined that USEC was "materially injured or threatened with material injury" by low-enriched uranium exported by European suppliers. The U.S. Department of Commerce (DOC) has assessed countervailing and anti-dumping duties against the European suppliers. Both USEC and the European suppliers have appealed these decisions. Generation is uncertain at this time as to the outcome of the pending appeals, however as a result of these actions Generation may incur higher costs for uranium enrichment services necessary for the production of nuclear fuel.

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

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

        Natural gas requirements for operating stations and other stations under construction will be procured through annual, monthly and spot-market purchases. Some fossil generation stations can use either oil or gas as fuel. Fuel oil inventories are managed such that in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months inventory levels are managed to take advantage of favorable market pricing. Generation uses financial instruments to mitigate price risk associated with multi-commodity price exposures. Generation also hedges forward price risk with both over-the-counter and exchange-traded instruments.

Power Team

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

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

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

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

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

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

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

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

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

 
    
    
   Power Only Purchases from
    
 
   Net Capacity
Purchases(1)
   Power Only
Sales
   AmerGen
   Non-Affiliates
   Transmission Rights
Purchases(2)
2003   $ 589   $ 2,442   $ 280   $ 1,722   $ 86
2004     639     1,088     292     768     93
2005     356     272     472     283     84
2006     328     92     472     239     3
2007     408     22     179     227     —
Thereafter     3,742     1     2,638     829     —
   
 
 
 
 
Total   $ 6,062   $ 3,917   $ 4,333   $ 4,068   $ 266
   
 
 
 
 
(1)
On October 2, 2002, Generation notified Midwest Generation of its exercise of termination options under the existing Collins and Peaking PPA. Generation exercised its termination options on 1,727 MWs in 2003 and 2004. In 2003, Generation will take 1,778 MWs of option capacity under the Collins and Peaking Unit Agreements as well as 1,265 MWs of option capacity under the Coal Generation PPA. Net capacity purchases in 2004 include 3,474 MWs of optional capacity from Midwest Generation. Net Capacity Purchases also include capacity sales to TXU under the PPA entered into in connection with the purchase of two generating plants in April 2002, which states that TXU will purchase the plant output from May through September from 2002 through 2006. During the periods covered by the PPA, TXU will make fixed capacity payments and will provide fuel to Generation in return for exclusive rights to the energy and capacity of the generation plants. The combined capacity of the two plants is 2,334 MWs.

(2)
Transmission Rights Purchases include estimated commitments in 2004 and 2005 for additional transmission rights that will be required to fulfill firm sales contracts.

        Additionally, Generation has the following commitments:

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

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

Capital Expenditures

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

 
   (in millions)
Production Plant   $ 566
Nuclear Fuel     397
   
  Total   $ 963
   

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

Sithe

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

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

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

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

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

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

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

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

AmerGen

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

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

30


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

Station
   Year Acquired
   Location
   License
Expiration
Date(1)
   Net Generation
Capacity (MW)
Clinton Nuclear Power Station   1999   Clinton, IL   2026   1,015
Unit 1 of Three Mile Island Nuclear Station   1999   Londonderry Twp., PA   2014   837
Oyster Creek Generating Station   2000   Forked River, NJ   2009   629
               
Total               2,481
               
(1)
AmerGen is reviewing the potential for license renewals for the Oyster Creek Generating Station (Oyster Creek) and Unit 1 of Three Mile Island Nuclear Station (TMI).

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

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

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

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

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

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

31


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

Enterprises

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

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

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

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

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

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

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

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

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

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

Employees

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

ComEd   7,000
PECO   2,700
Generation   7,200
Enterprises   7,500
BSC   800
   
Total   25,200
   

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

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

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

Environmental Regulation

General

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

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

Water

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

Solid and Hazardous Waste

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

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

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

34


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

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

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

MGP Sites

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

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

Air

        Air quality regulations promulgated by the EPA and the various State Environmental Agencies in Pennsylvania, Massachusetts, Illinois and Texas in accordance with the Federal Clean Air Act and the Clean Air Act Amendments of 1990 (Amendments) impose restrictions on emission of particulates, sulfur dioxide (SO2), nitrogen oxides (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 and the NOx Budget Program in the Ozone Transport Region (affecting facilities in Pennsylvania and Massachusetts).

        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 NOxregulation 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 court substantively upheld the original NOx regulation. Massachusetts, Illinois and Pennsylvania power plants are covered by the original NOxregulation. 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 NOxreduction regulations for power plants that satisfy both the original NOx regulation and the Section 126 Petition Regulation. Regulations are also in place in Massachusetts and Illinois. The Pennsylvania and Massachusetts regulations are effective on May 1, 2003. Exelon has evaluated options for compliance and is installing controls on the two coal units at Eddystone Generating Station (Selective Non-Catalytic Reduction) and the two coal units (Selective Catalytic Reduction) at Keystone Generating Station. In Massachusetts, an Air Quality Improvement Plan is in place for the Mystic Generating Station for compliance with the Massachusetts's multi-pollutant regulations. The plan includes restrictions to residual fuel oil consumption on units 4, 5 and 6; management of low sulfur fuels on unit 7, and dry low NOx combustors, Selective Catalytic Reduction and CO Oxidation Catalyst on the new gas-fired units 8 and 9 that will achieve commercial operation in 2003. The Exelon NOx

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

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

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

Costs

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

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

Other Subsidiaries of ComEd and PECO with Publicly Held Securities

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

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

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

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

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

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

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

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

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

Executive Officers of the Registrants at December 31, 2002

Exelon

Name
   Age
   Position
Rowe, John W.   57   Chairman, President and Chief Executive Officer
Kingsley Jr., Oliver D.   60   Senior Executive Vice President
McLean, Ian P.   53   Executive Vice President
Mehrberg, Randall E.   47   Executive Vice President and General Counsel
Moler, Elizabeth A.   53   Executive Vice President
Shapard, Robert S.   47   Executive Vice President and Chief Financial Officer
Strobel, Pamela B.   50   Executive Vice President
Clark, Frank M.   57   Senior Vice President
Gillis, Ruth Ann M.   48   Senior Vice President
Gilmore Jr., George H.   53   Senior Vice President
Lawrence, Kenneth G.   55   Senior Vice President
Mitchell, J. Barry   54   Senior Vice President and Treasurer
Skolds, John L.   52   Senior Vice President
Snodgrass, S. Gary   51   Senior Vice President and Chief Administrative Officer
Woods, David W.   45   Senior Vice President
Hilzinger, Matthew F.   39   Vice President and Corporate Controller
Lewis, Charles P.   39   Vice President, Strategy and Development, Generation

ComEd

Name
   Age
   Position
Rowe, John W.   57   Chairman, President and Chief Executive Officer, Exelon and Director
Strobel, Pamela B.   50   Chair
Shapard, Robert S.   47   Executive Vice President and Chief Financial Officer, Exelon*
Clark, Frank M.   57   President and Director
Gillis, Ruth Ann M.   48   Director
Lawrence, Kenneth G.   55   Director
Dudkin, Gregory N.   45   Executive Vice President, Operations
Berdelle, Robert E.   46   Vice President, Finance and Chief Financial Officer*
*
As a result of a reorganization of Exelon's finance function, Mr. Shapard became the principal financial officer of ComEd as of January 22, 2003.

39

PECO

Name
   Age
   Position
Rowe, John W.   57   Chairman, President and Chief Executive Officer, Exelon and Director
Strobel, Pamela B.   50   Chair
Shapard, Robert S.   47   Executive Vice President and Chief Financial Officer, Exelon*
Lawrence, Kenneth G.   55   President and Director
Frankowski, Frank F.   52   Vice President, Finance and Chief Financial Officer*
Gillis, Ruth Ann M.   48   Director
O'Brien, Denis P.   43   Executive Vice President
*
As a result of a reorganization of Exelon's finance function, Mr. Shapard became the principal financial officer of PECO as of January 22, 2003.

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

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

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

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

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

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

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

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

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

40


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

41



ITEM 2. PROPERTIES

Energy Delivery

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

Transmission and Distribution

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

 
   Voltage (Volts)
   Circuit Miles
ComEd   765,000
345,000
138,000		   90
2,539
2,431

PECO
 
500,000
220,000
132,000
66,000
 
297
496
226
168

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

Gas

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

 
   Pipeline Miles
Transmission   31
Distribution   6,275
Service piping   5,186
   
Total   11,492
   

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

Mortgages

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

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

42


Generation

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

Station
   Location
   No. of Units
   Percent Owned(1)
   Primary Fuel Type
   Dispatch Type
   Net Generation Capacity(MW)(2)
  
Nuclear(3)                          
Braidwood   Braidwood, IL   2       Uranium   Base-load   2,413  
Byron   Byron, IL   2       Uranium   Base-load   2,393  
Dresden   Morris, IL   2       Uranium   Base-load   1,728  
LaSalle County   Seneca, IL   2       Uranium   Base-load   2,325  
Limerick   Limerick Twp., PA   2       Uranium   Base-load   2,316  
Peach Bottom   Peach Bottom Twp., PA   2   50.00   Uranium   Base-load   1,130 (4)
Quad Cities   Cordova, IL   2   75.00   Uranium   Base-load   1,311 (4)
Salem   Hancock's Bridge, NJ   2   42.59   Uranium   Base-load   931 (4)
                       
 
                        14,547  
Fossil (Steam Turbines)                          
Conemaugh   New Florence, PA   2   20.72   Coal   Base-load   352 (4)
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  
Fairless Hills   Falls Twp., PA   2       Landfill Gas   Peaking   60  
Handley   Fort Worth, TX   5       Gas   Peaking/Intermediate   1,441  
Keystone   Shelocta, PA   2   20.99   Coal   Base-load   357 (4)
Mountain Creek   Dallas, TX   5       Gas   Peaking/Intermediate   893  
Mystic   Everett, MA   4       Oil/Gas   Intermediate   995  
New Boston   South Boston, MA   1       Gas   Intermediate   380  
Schuylkill   Philadelphia, PA   1       Oil   Peaking   166  
Wyman Unit   Yarmouth, ME   1   5.89   Oil   Intermediate   36 (4)
                       
 
                        6,616  
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  
Framingham   Framingham, MA   3       Oil   Peaking   37  
LaPorte   LaPorte, TX   4       Gas   Peaking   160  
Moser   Lower Pottsgrove Twp., PA   3       Oil   Peaking   51  
Mystic CT   Everett, MA   1       Oil   Peaking   12  
New Boston   South Boston, MA   1       Gas   Peaking   20  
Pennsbury   Falls Twp., PA   2       Landfill Gas   Peaking   6  
Richmond   Philadelphia, PA   2       Oil   Peaking   96  
Salem   Hancock's Bridge, NJ   1   42.59   Oil   Peaking   16 (4)
Schuylkill   Philadelphia, PA   2       Oil   Peaking   30  
South East Chicago   Chicago, IL   8       Gas   Peaking   350  
Southwark   Philadelphia, PA   4       Oil   Peaking   52  
West Medway   West Medway, MA   3       Oil   Peaking   165  
                       
 
                        1,581  
(continued on next page)              

43

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  
Under Construction                          
Mystic 8   Everett, MA   1       Gas       807  
Mystic 9   Everett, MA   1       Gas       807  
Fore River   Weymouth, MA   1       Oil/Gas       807  
                       
 
                        2,421  
       
             
 
Total       130               26,762  
       
             
 
(1)
100%, unless otherwise indicated.

(2)
For nuclear stations, except Salem, capacity reflects the annual mean rating. All other stations, including Salem, reflect a summer rating.

(3)
All nuclear stations are boiling water reactors except Braidwood, Byron and Salem, which are pressurized water reactors.

(4)
Generation's portion.

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

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


ITEM 3. LEGAL PROCEEDINGS

Exelon

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

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

44


ComEd

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

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

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

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

45


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

PECO

        None.

Generation

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

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

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

46


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

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

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

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

General

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


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

Exelon, ComEd and PECO

        None.

47


PART II

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

Exelon

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

ComEd

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

PECO

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

Exelon, ComEd, PECO and Generation

Dividends

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

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

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

 
   2002
   2001
  
 
   4th
Quarter
   3rd
Quarter
   2nd
Quarter
   1st
Quarter
   4th
Quarter
   3rd
Quarter
   2nd
Quarter
   1st
Quarter
  
 
   (per share)

  
Exelon   $ 0.44   $ 0.44   $ 0.44   $ 0.44   $ 0.43   $ 0.42   $ 0.42   $ 0.55 (1)
(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.

48

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

 
   2002
   2001
 
   4th
Quarter
   3rd
Quarter
   2nd
Quarter
   1st
Quarter
   4th
Quarter
   3rd
Quarter
   2nd
Quarter
   1st
Quarter
 
   (in millions)
ComEd   $ 117   $ 118   $ 117   $ 118   $ 230   $ 105   $ 85   $ 63
PECO   $ 85   $ 85   $ 85   $ 85   $ 173   $ 69   $ 55   $ 45

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

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

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

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


ITEM 6. SELECTED FINANCIAL DATA

Exelon

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

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ComEd

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

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

 
   For the Years
Ended December 31,
    
    
    
   For the Years
Ended December 31,
 
   Oct. 20-
Dec. 31
2000
    
   Jan. 1-
Oct. 19
2000
 
   2002
   2001
    
   1999
   1998
 
   (in millions)
Statement of Income Data:                     I                  
Operating Revenues   $ 6,124   $ 6,206   $ 1,310   I   $ 5,702   $ 6,793   $ 7,150
Operating Income     1,766     1,594     338   I     1,048     1,549     1,387
Net Income     790     607     133   I     599     623     594
Net Income on Common Stock     790     607     133   I     596     599     537

 
 
December 31,
 
   2002
   2001
   2000
    
   1999
   1998
 
   (in millions)
Balance Sheet Data:                     I            
Current Assets   $ 1,049   $ 1,025   $ 2,172   I   $ 4,045   $ 4,974
Property, Plant and Equipment, net     7,744     7,351     7,657   I     11,993     13,300
Goodwill, net     4,916     4,902     4,766   I     —     —
Other Deferred Debits and Other Assets     2,121     2,349     5,603   I     6,538     6,583
   
 
 
  I  
 
Total Assets   $ 15,830   $ 15,627   $ 20,198   I   $ 22,576   $ 24,857
   
 
 
  I  
 

Current Liabilities
 
$
2,023
 
$
1,797
 
$
1,723
 
I
 
$
3,427
 
$
3,309
Long-Term Debt     5,268     5,850     6,882   I     6,962     7,677
Deferred Credits and Other Liabilities     2,451     2,568     5,082   I     6,456     7,770
Mandatorily Redeemable Preference Stock     —     —     —   I     69     171
Company-Obligated Mandatorily Redeemable                     I            
Preferred Securities of Subsidiary Trusts Holding                     I            
the Company's Subordinated Debt Securities     330     329     328   I     350     350
Shareholders' Equity     5,758     5,083     6,183   I     5,312     5,580
   
 
 
  I  
 
Total Liabilities and Shareholders' Equity   $ 15,830   $ 15,627   $ 20,198   I   $ 22,576   $ 24,857
   
 
 
  I  
 

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PECO

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

 
   For the Years Ended December 31,
 
   2002
   2001
   2000
   1999
   1998
 
   (in millions)
Statement of Income Data:                              
Operating Revenues   $ 4,333   $ 3,965   $ 5,950   $ 5,478   $ 5,325
Operating Income     1,093     999     1,222     1,373     1,268
Income before Cumulative Effect of a Change in Accounting Principle   $ 486   $ 425   $ 483   $ 582   $ 513
Cumulative Effect of a Change in Accounting Principle (net of income taxes)     —     —     24     —     —
   
 
 
 
 
Net Income   $ 486   $ 425   $ 507   $ 582   $ 513
   
 
 
 
 
Net Income on Common Stock   $ 478   $ 415   $ 497   $ 570   $ 500
   
 
 
 
 

 
 
December 31,
 
   2002
   2001
   2000
   1999
   1998
 
   (in millions)
Balance Sheet Data:                              
Current Assets   $ 927   $ 813   $ 1,779   $ 1,221   $ 582
Property, Plant and Equipment, net     4,179     4,057     5,158     5,004     4,804
Deferred Debits and Other Assets     5,614     5,868     7,839     6,862     6,662
   
 
 
 
 
Total Assets   $ 10,720   $ 10,738   $ 14,776   $ 13,087   $ 12,048
   
 
 
 
 

Current Liabilities
 
$
1,576
 
$
1,335
 
$
2,974
 
$
1,286
 
$
1,735
Long-Term Debt     4,951     5,438     6,002     5,969     2,920
Deferred Credits and Other Liabilities     3,304     3,358     3,860     3,738     3,756
Company-Obligated Mandatorily Redeemable Preferred Securities     128     128     128     128     349
Mandatorily Redeemable Preferred Stock     —     19     37     56     93
Shareholders' Equity     761     460     1,775     1,910     3,195
   
 
 
 
 
Total Liabilities and Shareholders' Equity   $ 10,720   $ 10,738   $ 14,776   $ 13,087   $ 12,048
   
 
 
 
 

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Generation

        The selected consolidated financial data presented below has been derived from the audited financial statements of Generation. This data is qualified in its entirety by reference to, and should be read in conjunction with Generation'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,
 
   2002
   2001
   2000
   1999
 
   (in millions)
Statement of Income Data:                        
Operating Revenues   $ 6,858   $ 6,826   $ 3,274   $ 2,425
Operating Income     509     872     441     300
Income before Cumulative Effect of Changes in Accounting Principles   $ 387   $ 512   $ 260   $ 204
Cumulative Effect of Changes in Accounting Principles (net of income taxes)     13     12     —     —
   
 
 
 
Net Income (Loss)   $ 400   $ 524   $ 260   $ 204
   
 
 
 

 
 
December 31,
 
   2002
   2001
   2000
   1999
 
   (in millions)
Balance Sheet Data:                        
Current Assets   $ 1,805   $ 1,435   $ 1,793   $ 395
Property, Plant and Equipment, net     4,800     2,003     1,727     990
Deferred Debits and Other Assets     4,402     4,700     4,742     907
   
 
 
 
Total Assets   $ 11,007   $ 8,138   $ 8,262   $ 2,292
   
 
 
 

Current Liabilities
 
$
2,663
 
$
1,097
 
$
2,176
 
$
404
Long-Term Debt     2,132     1,021     205     209
Deferred Credits and Other Liabilities     3,259     3,212     3,271     729
Minority Interest     54     —     —     —
Members' Equity     2,899     2,808     2,610     950
   
 
 
 
Total Liabilities and Members' Equity   $ 11,007   $ 8,138   $ 8,262   $ 2,292
   
 
 
 

        The consolidated financial statements of Generation as of December 31, 2000 and for the year then ended present the financial position, results of operations and net cash flows of the generation-related business of Exelon prior to its corporate restructuring on January 1, 2001. Generation operated as a separate business subsequent to electric-industry restructuring in Pennsylvania effective January 1, 1999. Prior to that date, Exelon (and its predecessor, PECO) operated as a fully integrated electric and gas utility, and revenues and expenses were not separately identified in the accounting records

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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 99-3 to Exelon's Current Report on Form 8-K dated February 21, 2003.

ComEd, PECO and Generation

        Each Critical Accounting Estimate and New Accounting Pronouncement section presented below indicates the registrant or registrants to which each estimate or accounting standard is applicable. "We" or "Our" as utilized in the Critical Accounting Estimates and New Accounting Pronouncements sections is defined as the business units identified in each subheading.

Critical Accounting Estimates

        The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management discusses these estimates and assumptions with its Accounting and Disclosure Governance Committee on a regular basis and provides periodic updates to the Audit Committee of the Board of Directors on management decisions. Management believes that the following areas require significant management judgment in making estimates and assumptions to describe matters that are inherently uncertain and that may change in subsequent periods.

Accounting for Derivative Instruments (ComEd, PECO and Generation)

        We use derivative financial instruments primarily to manage commodity price and interest rate risks. In connection with our Risk Management Policy (RMP), we:

        Our derivative activities are subject to the management, direction, and control of our Risk Management Committee (RMC). The RMC sets forth risk management philosophy and objectives, and establishes procedures for control, valuation, counterparty credit approval, and the monitoring and reporting of our activities in derivative markets and the performance of our derivative contracts.

        We make estimates and assumptions concerning future commodity prices, load requirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and the changes in the fair value we expect in deciding whether or not to enter into derivative transactions, and in determining the initial accounting treatment for derivative transactions.

        We account for derivative financial instruments under SFAS No. 133. To the extent that changes in SFAS No. 133 modify current guidance, including the standards for determining whether contracts can be accounted for as normal purchases and normal sales, the accounting treatment for derivatives may change.

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        We are required under SFAS No. 133 to record derivative instruments at fair value. Depending on the designation of the derivative, the fair value is either recorded in the income statement or as a component of other comprehensive income in shareholders' equity (OCI). We use quoted exchange prices to the extent they are available or external broker quotes in order to determine the fair value of energy contracts. When external prices are not available, we use internal models to determine the fair value. These internal models include assumptions of the future prices of energy based on the specific energy market the energy is being purchased in using externally available forward market pricing curves for all periods possible under the pricing model. We use the Black model, a standard industry valuation model, to determine the fair value of energy derivative contracts that are marked-to-market. To determine the fair value of our outstanding interest rate swap agreements we use external broker quotes or calculate the fair value internally using the Bloomberg swap valuation tool. This tool uses the most recent market inputs and a widely accepted valuation methodology.

        During 2002, Generation recognized unrealized and realized net gains of $6 million and $20 million, respectively, relating to mark-to-market adjustments of certain non-trading purchased power and sale contracts pursuant to SFAS No. 133 and unrealized and realized net losses aggregating $9 million and $20 million, respectively, relating to mark-to-market adjustments of derivative instruments entered into for trading purposes.

        Hedge Accounting.    As part of our energy marketing business, we enter into contracts to purchase or sell electricity, gas and ancillary products such as transmission rights, congestion credits and emission allowances, using contracts that are considered derivatives under SFAS No. 133. Certain of these derivatives qualify as hedge transactions.

        A derivative 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). To qualify for hedge accounting, the fair value changes in the derivative must be expected to offset 80%-120% of the changes in fair value or cash flows of the hedged item. Changes in the fair value of a derivative that is designated and qualifies as a fair value hedge and is highly effective, 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 designated as and qualifies as a cash flow hedge and is highly effective, are recorded in OCI, until earnings are affected by the variability of cash flows being hedged. Exelon continually assesses these cash flow hedges to determine if they continue to be effective and that the forecasted future transaction is probable. At the point in time that the contract does not meet the effective or probable criteria of SFAS No. 133, hedge accounting is discontinued and the fair value of the derivative is recorded through earnings.

        Energy Contracts.    We enter into contracts designated as cash flow hedges in which we manage the variability of our cash flows related to the purchase or sale of energy. At the initiation of the contract the contract is identified as a cash flow hedge, which requires us to determine whether the contract is in accordance with our RMP, that the forecasted future transaction is probable, and that the hedging relationship between the energy contract and the expected future purchase or sale of energy is expected to be highly effective at the initiation of the hedge and throughout the hedging relationship. Internal models that measure the statistical correlation between the derivative and the associated hedged item determine the effectiveness of an energy contract designated as a hedge. An example of a contract that would qualify for hedge accounting would be a forward over-the-counter sales contract used to hedge an expected sale of generation exposed to market prices.

        Interest Rate Derivative Instruments.    We enter into interest rate swap contracts related to variable rate debt in order to convert the variable interest payments into fixed interest payments to manage the variability of cash flows. Additionally, we enter into forward-starting interest rate swaps in order to lock

54


in an interest rate at a future date in anticipation of a future debt issuance to manage the variability of changes in interest rates between the date of the decision to issue and the actual date of issue.

        We also enter into interest rate swap contracts related to fixed rate debt in order to maintain our targeted percentage of variable rate debt.

        The fair value of derivatives generally reflects the estimated amounts that we would receive or pay to terminate the contracts at the balance sheet date, thereby taking into account the current unrealized gains or losses of open contracts.

        Normal Purchases and Normal Sales Exemption.    As part of our energy marketing business, we enter into contracts to purchase or sell electricity, gas and ancillary products such as transmission rights, congestion credits and emission allowances using contracts that are considered derivatives under SFAS No. 133. The majority of these contracts, however, qualify for the normal purchases and normal sales SFAS No. 133 exemption from mark-to-market accounting treatment as they are for the purchase and sale of energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy related products in the retail and wholesale markets with the intent and ability to deliver or take delivery in quantities we expect to use or sell over a reasonable period in the normal course of business.

        These contracts are reflected in the financial statements at the lower of cost or market, on a portfolio basis, using the accrual method of accounting. We did not have any loss contracts as of December 31, 2002. Under these contracts we recognize any gains or losses when the underlying physical transaction affects earnings. At the initiation of the contract, we make a determination as to whether or not the contract meets the criteria as a normal purchase or normal sale. An example of an energy contract that would qualify for the normal sale exemption would include a forward sale contract under which we expect to supply the full requirements of the counterparty. An example of a contract that would qualify for the normal purchase exemption would be an energy capacity contract that we enter into to satisfy the needs of our customer base, either retail or wholesale.

        The availability of the normal purchases and normal sales exemption to specific contracts is based on a determination that at certain times excess generation is available for a forward sale and, similarly, a determination that at certain times generation supply will be insufficient to serve our load. The determination of the ability and intent to deliver or take delivery is based on internal models that forecast customer demand and electricity supply. These models include assumptions regarding customer load growth rates, which are influenced by the economy, weather and the impact of customer choice, and generating unit availability, particularly nuclear generating unit capability factors. Significant changes in these assumptions could result in contracts being considered differently under SFAS No. 133 and the potential requirement of mark-to-market accounting.

        Proprietary Trading.    As part of our energy trading operation, we enter into contracts to buy and sell energy for trading purposes. These contracts are recognized on the balance sheet at fair value and changes in the fair value are recognized through earnings. All proprietary trading activity is recorded net in revenue. Trading activities are a very small portion of Generation's overall power marketing activities. The trading portfolio is subject to stringent risk management limits and policies, including volumetric and depression limits to manage exposure to market risk, as prescribed by the RMC.

        Non-Trading Contracts.    To manage our commodity risk exposure and meet our load requirements, we have also entered into non-trading contracts that do not meet the definition in SFAS No. 133 of a normal purchase or normal sale or meet the requirements for hedge accounting treatment. These non-trading contracts are marked-to-market when the underlying item affects earnings, with the gains and losses recorded in Purchased Power and Fuel expense. Non-trading contracts are subject to stringent risk management limits and policies, as prescribed by the RMC.

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        Although we use derivative instruments to assist in managing commodity price and interest rate risks, we can still experience earnings volatility from period to period because of the risks associated with marketing and trading electricity and other energy-related products.

Regulatory Assets and Liabilities (ComEd and PECO)

        Energy Delivery's operating subsidiaries, ComEd and PECO, are regulated by their respective state regulatory commissions as well as by FERC. The regulators in Illinois and Pennsylvania, as well as FERC, use cost-based rate structures to determine the rates we charge customers. In establishing cost-based rates, the ICC and the PUC may consider the capital requirements and working capital needs to operate the distribution and transmission business, determine the operating cost levels that can be passed on to customers and provide for a reasonable return to our shareholders. In their determination of rates, the ICC and PUC may include allowable costs in periods other than the periods in which an unregulated entity would record the costs in the income statement. These costs are accounted for as either a regulatory asset or liability. Regulatory assets represent costs that have been deferred to future periods when it is probable that the regulator will allow for recovery through rates charged to customers. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred. Regulatory assets and liabilities are accounted for under SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71). Use of SFAS No. 71 is applicable to our utility operations that meet the following criteria: the operations are subject to third-party regulation of rates; the rates are cost-based; and the assumption that all costs will be recoverable from customers through rates is appropriate and reasonable. If a separable portion of our business no longer meets these criteria, we are required to eliminate the financial statement effects of regulation for that part of our business.

        Both ComEd and PECO are currently subject to rate freezes or rate caps that limit the opportunity to recover increased costs and the costs of new investment in facilities through rates during the rate freeze or rate cap period. Current rates include the recovery of our existing regulatory assets.

        The most significant regulatory assets we have recorded are:

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        For each regulatory jurisdiction where we conduct business, we continually assess whether the regulatory assets continue to meet the criteria for probable future recovery. This assessment includes consideration of factors such as changes in applicable regulatory environments, recent rate orders to other regulated entities in the same jurisdiction, the status of any pending or potential deregulation legislation and the ability to recover costs through regulated rates. If future recovery of costs ceases to be probable, the assets and liabilities would be recognized in current period earnings. A write-off of regulatory assets could impact our ability to pay dividends under PUHCA.

        Because our current rates include the recovery of existing regulatory assets and liabilities, and rates in effect during the rate freeze or rate cap periods are expected to allow us to earn a reasonable rate of return during that period, management believes the existing regulatory assets and liabilities are probable of recovery. This determination reflects the current political and regulatory climate in the states where we do business, but is subject to change in the future.

Nuclear Decommissioning (Generation)

        We currently have direct ownership interests in 16 active nuclear generating units and four retired nuclear generating units. In addition, we own a 50% equity interest in AmerGen, which operates three active nuclear generating units.

        In connection with the operation of our nuclear units, the NRC requires us to begin decommissioning these facilities after their NRC operating license lives end, generally 40 years from the date of initial operation, and complete the decommissioning within 60 years after cessation of operation. Generation has, however, requested or is in the process of requesting the extension of these license lives for several nuclear generating stations. The decommissioning of a nuclear generating station involves the decontamination of structures and components, the removal of high-level and

57


low-level radioactive materials from the site for disposal at a licensed facility and for certain stations, the restoration of the station sites to a natural state. We estimate that, once started, decommissioning of a site can generally be completed in 10 years. Based on the projected extended license lives of our nuclear plants, we will begin decommissioning our plants from 2014 through 2056, with expenditures primarily occurring when our operating plants are decommissioned, during the period from 2029 through 2056.

        PECO and ComEd currently recover certain decommissioning costs in regulated rates. The amounts recovered are deposited in trust accounts and invested for funding of future decommissioning costs for active and inactive generating units. As part of the 2001 corporate restructuring, the generation-related assets and liabilities of ComEd and PECO were transferred to Generation. The accounting for our receipt of decommissioning collections and recognition of decommissioning liabilities varies between the plants that were previously owned by ComEd or by PECO prior to restructuring.

        We account for the current period's cost of decommissioning related to generating plants previously owned by PECO by following regulatory accounting principles and recording a charge to depreciation expense and a corresponding liability in accumulated depreciation concurrent with decommissioning collections from rate payers. Our regulatory accounting principles for the generating stations previously owned by ComEd were discontinued when those stations were transferred to Generation. Those stations included both operating and retired units. For operating units, the difference between the current cost decommissioning estimate and the decommissioning liability recorded in accumulated depreciation is amortized to depreciation expense on a straight-line basis over the remaining lives. For retired units, the current cost decommissioning estimate is recorded in deferred credits and other liabilities and accreted to depreciation expense.

        Under regulatory accounting principles, gains and losses on marketable securities held in the nuclear decommissioning trust funds are reported in accumulated depreciation. After regulatory accounting principles are discontinued, unrealized gains and losses on marketable securities held in the nuclear decommissioning trust funds are reported in accumulated other comprehensive income. Realized gains and losses on decommissioning trust funds are reflected in other income and deductions in our Consolidated Statements of Income. Due to the sharp declines in the equity market since the third quarter of 2000, the value of our nuclear decommissioning trust funds has also decreased. In 2002, contributions to these trust funds of $112 million were offset by net realized and unrealized losses of $224 million, resulting in a 4% decrease in the trust funds' balance at December 31, 2002 compared to December 31, 2001. We believe that the amounts that ComEd and PECO are recovering from customers through electric rates, along with the earnings on the trust funds, will be sufficient to fund our decommissioning obligations.

        Cost estimates for decommissioning our nuclear facilities have been prepared by an independent engineering firm and reflect currently existing regulatory requirements and available technology. Our current estimate of our nuclear facilities' decommissioning cost is $7.4 billion in current year (2003) dollars. Calculating this estimate involves significant assumptions about the expected increases in decommissioning costs relative to general inflation rates, changes in the regulatory environment or regulatory requirements, and the timing of decommissioning. Significant changes in these assumptions could materially affect the liabilities and future costs related to decommissioning recorded in our Consolidated Financial Statements.

        The estimated service life of the nuclear station is also a significant assumption because decommissioning and depreciation costs are generally recognized over the life of the generating station. In 2001, we extended nuclear station service lives, over which the decommissioning costs are recognized, by 20 years. Effective April 1, 2001, we extended the estimated service lives by 20 years for three nuclear stations. Effective July 1, 2001, we extended the estimated service lives by 20 years for the remainder of Generation's operating nuclear stations. These changes were based on engineering

58


and economic feasibility studies we performed considering, among other things, future capital and maintenance expenditures at these plants. The service life extension is subject to NRC approval of an extension of existing NRC operating licenses. As a result of the change, net income for 2002 and 2001 increased approximately $132 million ($79 million, net of income taxes) and approximately $90 million ($60 million, net income taxes), respectively. Although we consider the service life extension authorization to be probable, if the extensions were denied, our results of operations would be adversely impacted by increased depreciation rates and accelerated future decommissioning payments.

        SFAS No. 143.    The accounting for our nuclear decommissioning obligation will be affected by the adoption of SFAS No. 143, "Asset Retirement Obligations" (SFAS No. 143) effective January 1, 2003. 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 under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel.

        The effect of this cumulative adjustment on nuclear decommissioning will be to change the decommissioning liability to reflect the fair value of the decommissioning obligation at the balance sheet date. Additionally, SFAS No. 143 will require the recording of an asset related to the decommissioning obligation, which will be amortized over the remaining lives of the plants. The net difference, between the asset recognized and the adjustment to the decommissioning liability, recorded upon adoption of SFAS No. 143 will be charged to earnings and recognized as a cumulative effect of a change in accounting principle, net of expected regulatory recovery and net of taxes. The decommissioning liability to be recorded will represent the fair value of the obligation for the future decommissioning of the plants and, as a result, accretion expense will be accrued on this liability until the obligation is satisfied.

        As noted above, we currently record the obligation for decommissioning ratably over the lives of the plants. We are currently in the process of evaluating the impact of adopting SFAS No. 143 on our financial condition. Based on the current information and the credit-adjusted risk-free rate, we estimate the increase in 2003 non-cash expense to impact earnings before the cumulative effect of a change in accounting principle for the adoption of SFAS No. 143 by approximately $30 million, after income taxes. Additionally, the adoption of SFAS No. 143 is expected to result in non-cash, one-time cumulative effect of a change in accounting principle gain of approximately $1.9 billion, after income taxes. The $1.9 billion gain and the $30 million charge includes our share of the impact of the SFAS No. 143 adoption related to AmerGen's nuclear plants. These impacts are based on our current interpretation of SFAS No. 143 and are subject to continued refinement based on the finalization of assumptions and interpretation at the time of adopting the standard, including the determination of the credit-adjusted risk-free rate. Under SFAS No. 143, the fair value of the nuclear decommissioning obligation will continue to be adjusted on an ongoing basis as these model input factors change.

        In accordance with SFAS No. 143, we used a probabilistic cash flow model with multiple scenarios in order to determine the fair value of the decommissioning obligation. SFAS No. 143 also stipulates that fair value represent the amount a third party would receive for assuming all of an entity's obligation. Key assumptions used in our determination of fair value as defined in SFAS No. 143 include:

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        Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy (DOE) is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste (SNF). As required by the NWPA, ComEd and PECO, each signed a contract with the DOE (Standard Contract) to provide for disposal of SNF from their respective nuclear generating stations. The NWPA and the Standard Contract required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance will be significantly delayed. The DOE currently estimates it will open a SNF facility in 2010. This extended delay requires us to retain possession of the SNF, thus increasing decommissioning costs including the operation and maintenance of facilities to store SNF until the DOE removes it from our sites.

        The NRC regulatory guidance suggests that decommissioning cost studies be updated every five years. Most of our studies were prepared in 1995 and 1996 and are in the process of being updated. Although no significant changes in decommissioning technologies have occurred since the studies were performed, and annual cost escalation studies are performed to determine the escalation factor applied to the base year cost study, changes in these cost studies could have a material impact on the fair value of the nuclear decommissioning obligation. The final determination of the cumulative effect of a change in accounting principle is also in part a function of the credit-adjusted risk-free rate at the time of the adoption of the standard. Additionally, although over the life of the plant, the charges to earnings for the depreciation of the asset and the interest on the liability will be equal to the amounts that would have been recognized as decommissioning expense under the current accounting, the timing of those charges will change and in the near-term period subsequent to adoption, the depreciation of the asset and the interest on the liability are expected to result in an increase in expense.

Asset Impairments

        Long-Lived Assets and Investments. (ComEd, PECO and Generation).    SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144), establishes accounting and reporting standards for both the impairment and disposal of long-lived assets. SFAS No. 144 continues the FASB requirements that:

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Accounting Principles Board Opinion No. 18, "The Equity Method of Accounting for Investment in Common Stock," requires that an impairment loss be recognized for an investment if the investment declines in fair value below its amortized cost basis, and this decline is judged to be other-than-temporary.

        We continually monitor our investments and businesses and the markets in which these businesses operate in order to determine events that may trigger an impairment. We test our businesses and investments for recoverability whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. Such triggering events may include a current expectation that there is a likelihood of 50% or greater that a long-lived asset will be sold, competitors' technological advancement, accelerated distributions of public holdings at a loss, lack of achievability of financial results versus plan, limited access to capital, or the loss of a major customer, among others. The analysis of impairment for long-lived and intangible assets is subject to an undiscounted cash flow analysis that requires significant assumptions.

        In 2002, ComEd, PECO and Generation did not identify factors through this review process that indicated potential impairment of property, plant and equipment or other long-lived assets.

        Goodwill (ComEd).    Under SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142), goodwill is also 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. If an impairment is determined at ComEd, the amount of the impaired goodwill will be written-off and expensed at ComEd.

        We performed the first step of the SFAS No. 142 impairment analysis, comparing the fair value of a reporting unit to its carrying amount, including goodwill, as of January 1, 2002, upon adoption of SFAS No. 142. That first step indicated no impairment of ComEd's goodwill. In performing the Step I tests as prescribed in SFAS No. 142, ComEd determined that discounted cash flow models would provide the most appropriate measure to determine Step I fair value. Consistent with the guidance in SFAS No. 142, ComEd prepared multiple scenario discounted cash flow models in order to determine the value for Step I of SFAS No. 142. These models use multiple assumptions including revenue growth rates, general expense escalation rates, allowed return on equity, a risk-adjusted discount rate and long-term earnings multiples of comparable companies. In addition to the above-noted assumptions, ComEd's model included varying assumptions regarding:

        The results of the Step I analysis for ComEd showed a weighted average probabilistic valuation of the multiple scenario discounted cash flows in excess of ComEd's book carrying amount, including goodwill, at December 31, 2001. Since the Step I calculated fair value was in excess of book value, we could conclude that ComEd's goodwill of $4.9 billion was not impaired.

        As required by SFAS No. 142, ComEd performed the annual update of ComEd's goodwill impairment analyses using a November 1, 2002 measurement date. This valuation determined the Step I calculated fair value of ComEd to be in excess of its book value at November 1, 2002. Since the Step I calculated fair value was in excess of book value, we concluded that goodwill was not impaired. Again, the probabilistic discounted cash flows model used in these analyses included the significant

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assumptions noted above. Rate changes were assumed to occur at various points in 2007 through 2009 in the different scenarios for ComEd based on the June 2002 extension of the rate freeze.

        Modifications to any of the assumptions discussed above, particularly changes in discount rates, long-term earnings multiples of comparable companies used to determine terminal values, and the expected results of rate proceedings, could result in a future impairment of goodwill. Actual results as well as market conditions in upcoming periods will impact the probabilities of scenarios used in the models. If the estimates of future cash flows in the ComEd model had been 10% lower, those discounted cash flows would still have been greater than the carrying values of ComEd. As we were not required to perform a Step II analysis at the November 1, 2002 measurement date for ComEd, a dollar amount for any potential impairment has not been determined. Because goodwill represents approximately 85% of ComEd's common equity, a potential future impairment of goodwill could significantly impact ComEd's ability to pay dividends to Exelon under PUHCA. The Illinois legislation provides that reductions to ComEd's common equity resulting from goodwill impairments will not impact ComEd's earnings cap calculation through 2006.

Defined Benefit Pension and Other Postretirement Welfare Benefits (ComEd, PECO and Generation)

        Exelon sponsors defined benefit pension plans and postretirement welfare benefit plans applicable to essentially all ComEd, PECO, and Generation employees. The costs of providing benefits under these plans are dependent on historical information such as employee age, length of service and level of compensation, and the actual rate of return on plan assets. Also, Exelon utilizes assumptions about the future, including the expected rate of return on plan assets, the discount rate applied to benefit obligations, rate of compensation increase and the anticipated rate of increase in health care costs. In accordance with SFAS No. 87, "Employer's Accounting for Pensions" (SFAS No. 87) and SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other than Pensions" the impact of changes in these factors on pension and other postretirement welfare benefit obligations is generally recognized over the expected remaining service life of the employees rather than immediately recognized in the income statement.

        In selecting the expected rate of return on plan assets, Exelon considered historical and expected returns for the types of investments the plans hold. Exelon's pension trust assets have lost $581 million, and $265 million, and gained $173 million in 2002, 2001 and 2000, respectively. The long-term expected rate of return on plan assets (EROA) assumption used in calculating pension cost was 9.5% at January 1, 2002, 2001 and 2000. Exelon generally maintains 60% of its plan assets in equity securities and 40% of its plan assets in fixed-income securities. Each quarter Exelon reviews the actual asset allocations and follows a rebalancing procedure in order to remain within an allowable range of these targeted percentages. Based on Exelon's asset allocation and long-term historical returns for both equity and fixed-income securities, Exelon set its EROA at 9.0% as of January 1, 2003 in order to calculate 2003 pension cost. Exelon's other postretirement benefit assets have lost $125 million, $14 million and $7 million in 2002, 2001 and 2000, respectively. The EROA assumption used in calculating the other postretirement benefit obligation was 8.8% at January 1, 2002, 2001 and 2000, respectively. Exelon will use an EROA assumption of 8.4% as of January 1, 2003 in order to calculate the 2003 other postretirement benefit costs. A lower EROA is used in the calculation of other postretirement benefit costs as the other postretirement benefit trust activity is partially taxable while the pension trust activity is non-taxable.

        Exelon uses the Moody's Aa Corporate Bond Index as a basis in selecting the discount rate. Exelon set the assumed discount rate at 7.35% and 6.75% at December 31, 2001 and 2002, respectively, in its estimate of pension expense and other postretirement benefit costs.

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        The following table illustrates the effect of changing the major actuarial assumptions discussed above:

Change in Actuarial Assumption
   Impact on
Projected Benefit
Obligation at
December 31, 2002
   Impact on
Pension Liability at
December 31, 2002
   Impact on
2003
Pension Cost
Pension Benefits                  
Decrease Discount Rate by 0.5%   $ 336   $ 336   $ 8
Decrease Rate of Return on Plan Assets by 0.5%     —     —     32
Change in Actuarial Assumption
   Impact on
Other Postretirement
Benefit Obligation
at December 31, 2002
   Impact on
Postretirement
Benefit Liability
at December 31, 2002
   Impact on 2003
Postretirement
Benefit Cost
Postretirement Benefits                  
Decrease Discount Rate by 0.5%   $ 152   $ —   $ 18
Decrease Rate of Return on Plan Assets by 0.5%     —     —     6

        The assumptions are reviewed at the beginning of each year during Exelon's annual review process. The impact of assumption changes are reflected in the recorded pension amounts consistent with assumption changes as they occur. As these assumptions change from period to period, recorded pension amounts and funding requirements could also change.

        Exelon's pension and other postretirement benefit plans have unrecognized losses of $2.1 billion and $0.8 billion, respectively, at December 31, 2002. This unrecognized loss primarily represents the difference between the expected return on plan assets and the actual return on plan assets that has not yet been recognized in pension or other postretirement benefit expense. Exelon generally amortizes these unrecognized (gains)/losses over five years; however, the annual amortization amounts vary based on actuarial determinations. Recognition of an unrecognized loss will result in increased net periodic pension cost going forward.

        Primarily as a result of sharp declines in the equity markets since the third quarter of 2000, Exelon recognized an additional minimum liability of $1.0 billion, net of income taxes, and an intangible asset of $211 million as prescribed by SFAS No. 87 in the fourth quarter of 2002. The liability was recorded as a reduction to shareholders' equity, and the equity will be restored to the balance sheet in future periods when the fair value of plan assets exceeds the accumulated benefit obligation. The recording of this additional minimum liability did not affect net income or cash flow in 2002 or compliance with debt covenants; however, pension cost and cash funding requirements could increase in future years without a substantial recovery in the equity markets.

        Exelon's defined benefit pension plans currently meet the minimum funding requirements of the Employment Retirement Income Security Act of 1974 without any additional funding; however, Exelon made a discretionary tax-deductible plan contribution of $150 million in the fourth quarter of 2002, of which $82 million and $60 million were funded by ComEd and Generation, respectively. Exelon also expects to make a discretionary tax-deductible plan contribution in 2003 of $300 million to $350 million.

        Approximately $15 million, $22 million and $37 million were included in operating and maintenance expense in 2002 for ComEd, PECO and Generation, respectively, for the cost of our pension and postretirement benefit plans, exclusive of the 2002 charges for employee severance programs. Although the 2003 increase in pension and postretirement benefit cost will depend on market conditions, Exelon's estimate is that expense will increase by approximately $48 million,

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$21 million and $52 million for ComEd, PECO and Generation, respectively, in 2003 from 2002 expense levels as the result of the effects of the decline in market value of plan assets in 2002, the decline in discount rate and increases in health care costs.

        In 2001, Exelon adopted a cash balance pension plan. All management and electing union employees who were hired by Exelon after 2001 became participants in the plan. Approximately 4,700 management employees who were active participants in Exelon's previous qualified defined benefit plans at December 31, 2000 and remained employed by Exelon on January 1, 2002 elected 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. This may result in increased cash requirements from pension plan assets, which may increase future funding to the pension plan.

Stock-Based Compensation Plans (ComEd, PECO and Generation)

        Exelon maintains a Long-Term Incentive Plan (LTIP) for certain full-time salaried employees and previously maintained a broad-based incentive program for certain other employees. The types of long-term incentive awards that have been granted under the LTIP are non-qualified options to purchase shares of our common stock and common stock awards. The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. Options granted under the LTIP and the broad-based incentive program become exercisable upon attainment of a target share value and/or time. All options expire 10 years from the date of grant.

        At December 31, 2002, there were 13,000,000 options authorized for issuance under Exelon's LTIP and 2,000,000 options authorized under Exelon's broad-based incentive program. ComEd, PECO and Generation currently follow the disclosure-only provisions of SFAS No. 123, "Accounting for Stock-Based Compensation" (SFAS No. 123). If ComEd, PECO and Generation had elected to account for stock-based compensation based on SFAS No. 123, ComEd, PECO and Generation would have recognized compensation expense as follows:

 
   2002
   2001
   2000
  
ComEd   $ 13   $ 10   $ 13 (a)
PECO     13     15     17  
Generation     15     9     10  
(a)
Includes Unicom expense of $3 million for the period of 2000 prior to the Merger.

        Exelon uses an independent actuarial firm to calculate the fair value of the options and to assist in the development of amounts required to be disclosed under SFAS No. 123. The key assumptions used in this determination of fair value are the expected volatility of the stock price, based on historical information; the expected life of the options, based on the vesting period and expiration date of the options; the estimated dividend yield, based on historical information adjusted for material known future changes; and the risk-free interest rate, based on the yield of a United States Treasury Strip available on the date of the grant and expiring at the approximate end of the option's term. Changes in these assumptions could have resulted in material changes in the amounts disclosed under SFAS No. 123 in ComEd, PECO and Generation's Consolidated Financial Statements.

Business Combinations (ComEd, PECO and Generation)

        In the three year period ended December 31, 2002, Exelon has completed several business combinations and asset acquisitions. Exelon adopted SFAS No. 141, "Business Combinations" (SFAS No. 141), as of January 1, 2002. SFAS No. 141 is effective for business combinations initiated after June 30, 2001. SFAS No. 141 requires that all business combinations be accounted for under the

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purchase method of accounting and establishes criteria for the separate recognition of intangible assets acquired in business combinations. Under the purchase method of accounting, purchased assets and liabilities must be recorded at their fair value. If a quoted fair value is not readily available for the majority of assets and liabilities exchanged, the determination of this fair value requires the use of significant judgment, both by management and outside experts engaged to assist in this determination process. Changes in the assumptions made in determining the fair values could have resulted in material changes in the amounts disclosed in Note 3 of the Notes to ComEd's Consolidated Financial Statements, Note 5 of the Notes to PECO's Consolidated Financial Statements and Notes 2 and 4 of the Notes to Generation's Consolidated Financial Statements. There would also be an impact on Exelon's financial results. If the fair value of property, plant and equipment acquired in a business combination would have been higher, and an amount allocated to goodwill in the business combination lower, depreciation expense would have been higher. Conversely, if the fair value of property, plant and equipment acquired in a business combination would have been lower, and an amount allocated to goodwill in the business combination higher, depreciation expense would have been lower. For example, if the $2 billion fair value of the generating plants acquired in the Merger was estimated to be 1% higher, then annual depreciation expense would be less than $1 million higher and goodwill amortization, which ceased in 2002, would have been less than $1 million lower annually.

Unbilled Energy Revenues (ComEd, PECO and Generation)

        Revenues related to ComEd and PECO's sale of energy are generally recorded when service is rendered or energy is delivered to customers. The determination of the energy sales to individual customers, however, is based on systematic readings of customer meters generally on a monthly basis. At the end of each month, amounts of energy delivered to customers during the month since the date of the last meter reading are estimated and corresponding unbilled revenue is recorded. This unbilled revenue is estimated each month based on daily customer demand measured by generation volume, estimated customer usage by class, estimated losses of energy during delivery to customers (line loss) and applicable customer rates. Customer accounts receivable as of December 31, 2002 include unbilled energy revenues of $250 million on a base of annual revenue of $6.1 billion for ComEd and $129 million on a base of annual revenue of $4.3 billion for PECO. Increases in volumes delivered to the utilities' customers in the period would increase unbilled revenue. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date would also have an effect on the estimated unbilled revenue.

        Revenues related to Generation's sale of energy are generally recorded when service is rendered or energy is delivered to customers. The determination of the energy sales is based on estimated amounts delivered as well as fixed quantity sales. At the end of each month, amounts of energy delivered to customers during the month and corresponding unbilled revenue is recorded. This unbilled revenue is estimated each month based on daily customer demand, fixed quantity sales, generation volume and applicable market or fixed rates. Customer accounts receivable as of December 31, 2002 include unbilled energy revenues of $370 million on a base of annual revenue of $6.9 billion. Increases in volumes delivered to the wholesale customers in the period would increase unbilled revenue.

Environmental Costs (ComEd, PECO and Generation)

        As of December 31, 2002, ComEd, PECO and Generation had accrued liabilities of $101 million, $40 million and $15 million, respectively, for environmental investigation and remediation costs. These liabilities are based upon estimates with respect to the number of sites for which we 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, scope and expenditures of remediation efforts can be reasonably estimated, amounts are discounted. These amounts, recorded at ComEd, represent $97 million of the total ComEd accrued liabilities above. Where the timing, scope

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and expenditures of remediation efforts cannot be reasonably estimated, amounts are recognized on an undiscounted basis. Such amounts represent $4 million, $40 million and $15 million of the total accrued liabilities above for ComEd, PECO and Generation, respectively. Estimates can be affected by the factors noted above as well as by changes in technology and changes in regulations or the requirements of Federal, state and local governmental authorities. During 2002, ComEd increased its reserve for environmental costs by $17 million as the result of a delay in implementing the ongoing remediation for a manufactured gas plant site in Oak Park, Illinois.

New Accounting Pronouncements

SFAS No. 143 (ComEd, PECO and Generation)

        In 2001, the FASB issued SFAS No. 143. SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. We will adopt SFAS No. 143 as of January 1, 2003. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. Adoption of SFAS No. 143 will change the accounting for the decommissioning of our nuclear generating plants as well as certain other long-lived assets. ComEd, PECO and Generation are in the process of evaluating the impact of adopting SFAS No. 143 on their financial condition. While ComEd and PECO do not expect the adoption of SFAS No. 143 to have a material impact on their financial condition, Generation does expect the adoption of SFAS No. 143 to have a material impact on its financial condition related to its obligation to decommission its nuclear generating plants.

        As it relates to nuclear decommissioning, the effect of a cumulative adjustment will be to decrease the decommissioning liability to reflect the fair value of the decommissioning obligation at the balance sheet date. Additionally, SFAS No. 143 will require the recognition of an asset related to the decommissioning obligation, which will be amortized over the remaining lives of the plants. The net difference, between the asset recognized and the change in the liability to reflect fair value recorded upon adoption of SFAS No. 143, will be recorded in earnings and recognized as a cumulative effect of a change in accounting principle, net of expected regulatory recovery and income taxes. The decommissioning liability will then represent an obligation for the future decommissioning of the plants and, as a result, accretion expense will be accrued on this liability until the obligation is satisfied.

        Currently, Generation records the obligation for decommissioning ratably over the lives of the plants. Based on the current information and the credit-adjusted risk-free rate, Generation estimates the increase in 2003 non-cash expense to impact Generation earnings before the cumulative effect of a change in accounting principle for the adoption of SFAS No. 143 by approximately $30 million, after income taxes. Additionally, the adoption of SFAS No. 143 is expected to result in a non-cash, one-time cumulative effect of a change in accounting principle gain at Generation of approximately $1.9 billion, after income taxes. The $1.9 billion gain and the $30 million charge includes Generation's share of the impact of the SFAS No. 143 adoption related to AmerGen's nuclear plants. These impacts are based on Generation's current interpretation of SFAS No. 143 and are subject to continued refinement based on the finalization of assumptions and interpretation at the time of adopting the standard, including the determination of the credit-adjusted risk-free rate. Under SFAS No. 143, the fair value of the nuclear decommissioning obligation will continue to be adjusted on an ongoing basis as these model input factors change.

        The final determination of the 2003 earnings impact and the cumulative effect of adopting SFAS No. 143 is in part a function of the credit adjusted risk-free rate at the time of the adoption of SFAS No. 143. Additionally, although over the life of the plant the charges to earnings for the depreciation of the asset and the interest on the liability will be equal to the amounts that would have been recognized as decommissioning expense under current accounting, the timing of those charges will change and in

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the near-term period subsequent to adoption, the depreciation of the asset and the interest on the liability is expected to result in an increase in expense.

SFAS No. 146 (ComEd, PECO and Generation)

        In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146 requires that the liability for costs associated with exit or disposal activities be recognized when incurred, rather than at the date of a commitment to an exit or disposal plan. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002.

FIN No. 45 (ComEd, PECO and Generation)

        In November 2002, the FASB released FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN No. 45), providing for expanded disclosures and recognition of a liability for the fair value of the obligation undertaken by the guarantor. Under FIN No. 45, guarantors are required to disclose the nature of the guarantee, the maximum amount of potential future payments, the carrying amount of the liability and the nature and amount of recourse provisions or available collateral that would be recoverable by the guarantor. As of December 31, 2002, we have adopted disclosure requirements under FIN No. 45, which were effective for financial statements for periods ended after December 15, 2002. The recognition and measurement provisions of FIN No. 45 are effective, on a prospective basis, for guarantees issued or modified after December 31, 2002.

FIN No. 46 (ComEd, PECO and Generation)

        In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable Interest Entities" (FIN No. 46). FIN No. 46 addresses consolidating certain variable interest entities and applies immediately to variable interest entities created after January 31, 2003. The impact, if any, of adopting FIN 46 on our consolidated financial position, results of operations and cash flows, has not been fully determined.

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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 principally consist of the purchase, transmission, distribution and sale of electricity 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.

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Results of Operations

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

Significant Operating Trends—ComEd

 
   2002
   2001
   Variance
   % Change
  
OPERATING REVENUES   $ 6,124   $ 6,206   $ (82 ) (1.3 )%

OPERATING EXPENSES
 
 
 
 
 
 
 
 
 
 
 
 
  Purchased Power     2,585     2,670     (85 ) (3.2 )%
  Operating and Maintenance     964     981     (17 ) (1.7 )%
  Depreciation and Amortization     522     665     (143 ) (21.5 )%
  Taxes Other Than Income     287     296     (9 ) (3.0 )%
   
 
 
 
 
    Total Operating Expense     4,358     4,612     (254 ) (5.5 )%
   
 
 
 
 
OPERATING INCOME     1,766     1,594     172   10.8%  
   
 
 
 
 

OTHER INCOME AND DEDUCTIONS
 
 
 
 
 
 
 
 
 
 
 
 
  Interest Expense     (484 )   (565 )   81   (14.3 )%
  Distributions on Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely the Company's Subordinated Debt Securities     (30 )   (30 )   —   —  
  Other, Net     44     114     (70 ) (61.4 )%
   
 
 
 
 
    Total Other Income and Deductions     (470 )   (481 )   11   (2.3 )%
   
 
 
 
 

INCOME BEFORE INCOME TAXES
 
 
1,296
 
 
1,113
 
 
183
 
16.4%
 
INCOME TAXES     506     506     —   —  
   
 
 
 
 
NET INCOME   $ 790   $ 607   $ 183   30.1%  
   
 
 
 
 

Net Income

        Net income increased $183 million, or 30% in 2002. Net income was primarily impacted by the discontinuation of goodwill amortization, lower depreciation rates effective August 1, 2002, lower interest expense and a lower effective income tax rate partially offset by the effects of a 5% residential rate reduction effective October 1, 2001, customers electing to purchase energy from an ARES or the PPO and lower intercompany interest income.

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Operating Revenues

        ComEd's electric sales statistics are as follows:

Retail Deliveries—(in GWhs)(1)
   2002
   2001
   Variance
   % Change
  
Bundled Deliveries(2)                  
Residential   27,474   25,282   2,192   8.7 %
Small Commercial & Industrial   22,365   23,435   (1,070 ) (4.6 )%
Large Commercial & Industrial   7,885   10,305   (2,420 ) (23.5 )%
Public Authorities & Electric Railroads   6,480   7,879   (1,399 ) (17.8 )%
   
 
 
 
 
    64,204   66,901   (2,697 ) (4.0 )%
   
 
 
 
 
Unbundled Deliveries(3)                  
ARES                  
Small Commercial & Industrial   5,219   2,865   2,354   82.2 %
Large Commercial & Industrial   7,095   5,458   1,637   30.0 %
Public Authorities & Electric Railroads   912   365   547   149.9 %
   
 
 
 
 
    13,226   8,688   4,538   52.2 %
   
 
 
 
 
PPO                  
Small Commercial & Industrial   3,152   3,279   (127 ) (3.9 )%
Large Commercial & Industrial   5,131   5,750   (619 ) (10.8 )%
Public Authorities & Electric Railroads   1,347   987   360   36.5 %
   
 
 
 
 
    9,630   10,016   (386 ) (3.9 )%
   
 
 
 
 
  Total Unbundled Deliveries   22,856   18,704   4,152   22.2 %
   
 
 
 
 
Total Retail Deliveries   87,060   85,605   1,455   1.7 %
   
 
 
 
 
(1)
One GWh is the equivalent of one million kWhs.

(2)
Bundled service reflects deliveries to customers taking electric service under tariffed rates.

(3)
Unbundled service reflects customers electing to receive electric generation service from an ARES or the PPO.

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Electric Revenue
   2002
   2001
   Variance
   % Change
  
Bundled Revenues(1)                        
Residential   $ 2,381   $ 2,308   $ 73   3.2 %
Small Commercial & Industrial     1,736     1,821     (85 ) (4.7 )%
Large Commercial & Industrial     410     523     (113 ) (21.6 )%
Public Authorities & Electric Railroads     377     430     (53 ) (12.3 )%
   
 
 
 
 
      4,904     5,082     (178 ) (3.5 )%
   
 
 
 
 
Unbundled Revenues(2)                        
ARES                        
Small Commercial & Industrial     138     48     90   187.5 %
Large Commercial & Industrial     154     74     80   108.1 %
Public Authorities & Electric Railroads     28     5     23   n.m.  
   
 
 
 
 
      320     127     193   152.0 %
   
 
 
 
 
PPO                        
Small Commercial & Industrial     204     220     (16 ) (7.3 )%
Large Commercial & Industrial     278     343     (65 ) (19.0 )%
Public Authorities & Electric Railroads     71     59     12   20.3 %
   
 
 
 
 
      553     622     (69 ) (11.1 )%
   
 
 
 
 
Total Unbundled Revenues     873     749     124   16.6 %
   
 
 
 
 
Total Electric Retail Revenues     5,777     5,831     (54 ) (0.9 )%
Wholesale and Miscellaneous Revenue(3)     347     375     (28 ) (7.5 )%
   
 
 
 
 
Total Electric Revenue   $ 6,124   $ 6,206   $ (82 ) (1.3 )%
   
 
 
 
 
(1)
Bundled revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy.

(2)
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. Revenues from customers choosing the PPO includes an energy charge at market rates, transmission, and distribution charges and a CTC charge.

(3)
Wholesale and miscellaneous revenues include transmission revenue, sales to municipalities and other wholesale energy sales.

        The changes in electric retail revenues in 2002, as compared to 2001, were attributable to the following:

 
   Variance
  
Customer Choice   $ (131 )
Rate Changes     (99 )
Weather     88  
Volume     91  
Other Effects     (3 )
   
 
Retail Revenue   $ (54 )
   
 
•
Customer Choice.  The decrease in revenues reflects customers in Illinois electing to purchase energy from an ARES or the PPO. As of December 31, 2002, approximately 22,700 retail customers had elected to purchase energy from an ARES or the ComEd PPO, an increase from 18,700 customers at December 31, 2001. The megawatthours (MWhs or the equivalent of one thousand KWhs) delivered to such customers increased from approximately 18.7 million in 2001 to 22.9 million in 2002, a 22% increase from the previous year.

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•
Rate Changes.  The decrease attributable to rate changes reflects a 5% residential rate reduction, effective October 1, 2001, required by the Illinois restructuring legislation.

•
Weather.  The demand for electricity service 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 for 2002 was favorable compared to 2001 as a result of warmer summer weather and slightly cooler winter weather in 2002 compared to 2001. Cooling degree-days increased 29% and heating degree-days increased 3% in 2002 compared to 2001.

•
Volume.  Revenues from higher delivery volume, exclusive of weather, increased due to an increased number of customers and increased usage per customer, primarily residential.

        The reduction in wholesale and miscellaneous revenue in 2002 as compared to 2001 was due primarily to a $38 million decrease 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, and a $15 million reversal of reserve for revenue refunds in 2001 related to certain of ComEd's municipal customers as a result of a favorable FERC ruling, partially offset by a reimbursement from Generation of $12 million for third-party energy reconciliations and $13 million of other miscellaneous revenue.

Purchased Power

        Purchased power expense decreased $85 million, or 3% in 2002. The decrease in purchased power expense was primarily attributable to a $145 million decrease as a result of customers choosing to purchase energy from an ARES and a $34 million decrease due to the expiration of the wholesale contracts offered by ComEd to support the open access program in Illinois partially offset by a $41 million increase associated with increased retail demand due to favorable weather conditions, a $16 million increase due to the effects of increased weather-normalized volumes for residential and small commercial and industrial customers, an $18 million increase due to an increase in the weighted average on-peak/off-peak cost per MWh of electricity and $20 million in additional expense as a result of third-party energy reconciliations.

Operating and Maintenance

        The $17 million decrease in operating and maintenance (O&M) expense is comprised of $32 million of lower payroll costs due to employee reductions, $16 million in cost reductions from Exelon's Cost Management Initiative and $24 million miscellaneous other net positive impacts, partially offset by $25 million in additional employee benefit costs, a $16 million net increase in environmental and remediation expense and a $14 million increase in injuries and damages expense.

Depreciation and Amortization

        Depreciation and amortization expense decreased $143 million, or 22%, in 2002 as follows:

 
   2002
   2001
   Variance
   % Change
  
Depreciation Expense   $ 334   $ 353   $ (19 ) (5.4 )%
Recoverable Transition Costs Amortization     102     108     (6 ) (5.6 )%
Other Amortization Expense     86     204     (118 ) (57.8 )%
   
 
 
 
 
Total Depreciation and Amortization   $ 522   $ 665   $ (143 ) (21.5 )%
   
 
 
 
 

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        The decrease in depreciation expense is due to a $48 million decrease related to lower depreciation rates partially offset by the effect of higher in-service property, plant and equipment balances.

        Recoverable transition costs amortization expense is determined using the expected period of the rate freeze and the expected returns in the periods under the rate freeze. The reduction in amortization expense in 2002 is due to the extension of the rate freeze in the second quarter of 2002. ComEd expects to fully recover these assets by the end of 2006.

        The decrease in Other Amortization Expense is primarily attributable to the discontinuation of amortization of goodwill as required by SFAS No. 142. During 2001, $126 million of goodwill was amortized.

Taxes Other Than Income

        Taxes other than income decreased by $9 million, or 3% in 2002. The primary positive impact was the result of real estate tax refunds in the amount of $5 million.

Interest Charges

        Interest charges decreased $81 million, or 14% in 2002. The decrease in interest charges was primarily attributable to the impact of lower interest rates for 2002 as compared to 2001, the early retirement of $196 million of First Mortgage Bonds in November of 2001, the retirement of $340 million in transitional trust notes during 2002, and $10 million of intercompany interest expense in 2001 relating to a payable in Generation, which was repaid during 2001.

Other Income and Deductions

        Other income and deductions, excluding interest charges, decreased $70 million, or 61%, in 2002. The decrease was primarily attributable to $8 million in intercompany interest income relating to the $400 million receivable from PECO which was repaid during the second quarter of 2001, a $31 million reduction in intercompany interest income from Unicom Investment Inc., reflecting lower interest rates, $9 million in intercompany interest income from Generation in 2001 on the processing of certain invoice payments on behalf of Generation, a $12 million reserve for a potential plant disallowance resulting from an audit performed in conjunction with ComEd's delivery services rate case, and an $10 million decrease in various other income and deductions items.

Income Taxes

        The effective income tax rate was 39.0% in 2002, compared to 45.5% in 2001. The decrease in the effective tax rate was primarily attributable to the discontinuation of goodwill amortization as of January 1, 2002, which was not deductible for income tax purposes, and other tax benefits recorded in 2002.

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

Summary Financial Information—ComEd

 
    
    
   Components of Variance
  
 
   2001
   2000
   Restructuring
Impact
   Normal
Operations
   Total
  
 
   (in millions)

  
OPERATING REVENUES   $ 6,206   $ 7,012   $ (707 ) $ (99 ) $ (806 )
 
Purchased Power and Fuel
 
 
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  
   
 
 
 
 
 

OTHER INCOME AND DEDUCTIONS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Interest Expense     (565 )   (602 )   43     (6 )   37  
  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 )
   
 
 
 
 
 
      Total Other Income and Deductions     (481 )   (324 )   43     (200 )   (157 )
   
 
 
 
 
 

INCOME BEFORE INCOME TAXES
 
 
1,113
 
 
1,062
 
 
144
 
 
(93
)
 
51
 

INCOME TAXES
 
 
506
 
 
330
 
 
72
 
 
104
 
 
176
 
   
 
 
 
 
 

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.

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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 GWhs)
   2001
   2000
   Variance
  
Bundled Deliveries(1)              
Residential   25,282   23,997   1,285  
Small Commercial & Industrial   23,435   24,833   (1,398 )
Large Commercial & Industrial   10,305   15,348   (5,043 )
Public Authorities & Electric Railroads   7,879   7,665   214  
   
 
 
 
    66,901   71,843   (4,942 )
   
 
 
 
Unbundled Deliveries(2)              
ARES              
Small Commercial & Industrial   2,865   2,772   93  
Large Commercial & Industrial   5,458   5,807   (349 )
Public Authorities & Electric Railroads   365   297   68  
   
 
 
 
    8,688   8,876   (188 )
   
 
 
 
PPO              
Small Commercial & Industrial   3,279   1,433   1,846  
Large Commercial & Industrial   5,750   2,812   2,938  
Public Authorities & Electric Railroads   987   1,088   (101 )
   
 
 
 
    10,016   5,333   4,683  
   
 
 
 
Total Unbundled Deliveries   18,704   14,209   4,495  
   
 
 
 
Total Retail Deliveries   85,605   86,052   (447 )
   
 
 
 
(1)
Bundled service reflects deliveries to customers taking electric service under tariffed rates.

(2)
Unbundled service reflects customers electing to receive electric generation service from an ARES or the PPO.

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Electric Revenue
   2001
   2000
   Variance
  
 
   (in millions)

  
Bundled Revenue(1)                    
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(2)                    
ARES                    
Small Commercial & Industrial     48     62     (14 )
Large Commercial & Industrial     74     115     (41 )
Public Authorities & Electric Railroads     5     7     (2 )
   
 
 
 
      127     184     (57 )
   
 
 
 
PPO                    
Small Commercial & Industrial     220     92     128  
Large Commercial & Industrial     343     158     185  
Public Authorities & Electric Railroads     59     56     3  
   
 
 
 
      622     306     316  
   
 
 
 
  Total Unbundled Revenues     749     490     259  
   
 
 
 
Total Electric Retail Revenues     5,831     5,909     (78 )
  Wholesale and Miscellaneous Revenue(3)     375     396 (4)   (21 )
   
 
 
 
Total Electric Revenues   $ 6,206   $ 6,305   $ (99 )
   
 
 
 
(1)
Bundled revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy.

(2)
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. Revenues from customers choosing the PPO includes an energy charge at market rates, transmission, and distribution charges and a CTC charge.

(3)
Wholesale and miscellaneous revenues include transmission revenue, sales to municipalities and other wholesale energy sales.

(4)
Includes the operations of ComEd as if the 2001 corporate restructuring had occurred on January 1, 2000.

        The changes in electric retail revenues for 2001, as compared to 2000, were attributable to the following:

 
   Variance
  
 
   (in millions)

  
Customer Choice   $ (145 )
Weather     103  
Revenue Taxes     (88 )
Other Effects     76  
Rate Changes     (24 )
   
 
Electric Retail Revenue   $ (78 )
   
 
•
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,

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•
Weather.  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.

•
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.

•
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.

•
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.

Purchased Power and Fuel

        Purchased power and fuel expense increased $16 million, or 1%, compared to 2000, excluding the effects of restructuring. The increase in purchased power and fuel expense was primarily attributable to increases in the weighted average on-peak/off-peak cost per MWh, partially offset by a decrease in MWhs purchased.

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 for eligible employees whose positions were eliminated before October 20, 2000 due to planned integration activities of the merged companies.

Depreciation and Amortization

        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

77


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 and Supplementary Data—ComEd Note 5 of the Notes to Consolidated Financial Statements. Annual goodwill amortization of $126 million in 2001 was discontinued in 2002 upon the adoption of 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 $6 million, or 1%, 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 Unicom Investment, Inc., reflecting the impact of declining interest rates and an $850 million reduction in intercompany notes receivable 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.

Liquidity and Capital Resources

        ComEd's business is capital intensive and requires considerable 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 general business conditions, as well as that of the utility industry in general. Capital resources are used primarily to fund ComEd's capital requirements, including construction, repayments of maturing debt and the payment of dividends.

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Cash Flows from Operating Activities

        Cash flows provided by operations in 2002 were $2.0 billion as compared to $1.3 billion in 2001. The increase in cash flows in 2002 was primarily attributable to a $183 million increase in net income, a $175 million increase in other operating activities, and a $422 million increase in working capital partially offset by a decrease of $143 million in depreciation and amortization. ComEd's future cash flows will depend upon the ability to achieve reductions in operating costs, 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 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.

        ComEd participates in Exelon's defined benefit pension plans. Exelon's plans currently meet the minimum funding requirements of the Employment Retirement Income Security Act of 1974; however, Exelon made a $150 million discretionary plan contribution in 2002, $82 million of which was funded by ComEd. Exelon also expects to make a discretionary plan contribution of $300 million to $350 million in 2003.

Cash Flows from Investing Activities

        Cash flows used in investing activities were $759 million in 2002 compared to $458 million in 2001. The increase in cash flows used in investing activities in 2002 was primarily attributable to the paydown of the $400 million outstanding receivable from PECO in the second quarter of 2001 partially offset by an $89 million decrease in capital expenditures. ComEd's investing activities for the year ended December 31, 2002 were funded primarily through operating activities.

        ComEd estimates that it will spend approximately $720 million in total capital expenditures for 2003. Approximately two thirds of the budgeted 2003 expenditures are for continuing efforts to further improve the reliability of its transmission and distribution systems. The remaining one third is for capital additions to support new business and customer 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 in 2002 were $1,231 million as compared to $1,006 million in 2001. Cash flows used in financing activities were primarily attributable to debt service and payments of dividends to Exelon. ComEd's debt financing activities in 2002 reflected the issuance of $600 million of First Mortgage Bonds, the issuance of $100 million of Illinois Development Finance Authority floating-rate Pollution Control Revenue Refunding Bonds, the retirement of $340 million of transitional trust notes, the redemption of $600 million in First Mortgage Bonds with available cash, the payment at maturity of $200 million in First Mortgage Bonds, the payment at maturity of $200 million in variable rate senior notes, the payment at maturity of $100 million of fixed-rate medium-term notes and the redemption of $100 million of 7.25% Illinois Development Finance Authority Pollution Control Revenue Refunding Bonds. As of December 31, 2002, ComEd had $123 million in short-term borrowings of which $52 million has been classified as long-term debt. In 2001, ComEd's debt financing activities reflected the retirement of $340 million of transitional trust notes and the redemption of $196 million in First Mortgage Bonds. ComEd paid a $470 million dividend to Exelon during 2002 compared to a $483 million dividend in 2001.

Credit Issues

        ComEd meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from Exelon's intercompany money pool. ComEd, along with Exelon, PECO, and

79


Generation, participates in a $1.5 billion unsecured 364-day revolving credit facility with a group of banks. The credit facility that became effective on November 22, 2002, includes a term-out option that allows any outstanding borrowings at the end of the revolving credit period to be repaid on November 21, 2004. Exelon may increase or decrease the sublimits of each of the participants upon written notification to the banks. As of December 31, 2002, ComEd's sublimit was $200 million. The credit facility is used principally to support ComEd's commercial paper program. At December 31, 2002, ComEd's Balance Sheet reflects $123 million in commercial paper outstanding, of which $52 million was classified as long-term debt.

        For 2002, the average interest rate on notes payable was approximately 1.69%. Certain of the credit agreements to which ComEd is a party require it to maintain a cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratio excludes revenues and interest expenses attributed to securitization debt, certain changes in working capital, and distributions on preferred securities of subsidiaries. ComEd's threshold for the ratio reflected in the credit agreement cannot be less than 2.25 to 1 for the twelve-month period ended December 31, 2002. At December 31, 2002, ComEd was in compliance with the credit agreement thresholds.

        At December 31, 2002, ComEd's capital structure, excluding the deduction from shareholders' equity of the $615 million receivable from Exelon, consisted of 46% long-term debt, 50% of common stock, 3% of preferred securities of subsidiaries, and 1% of notes payable. Long-term debt included $2.0 billion of transitional trust notes constituting obligations of certain consolidated special purpose entities representing 16% of capitalization.

        To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. Participation in the money pool is subject to authorization by the Exelon corporate treasurer. ComEd and its subsidiary Commonwealth Edison of Indiana, Inc., PECO, Generation and BSC may participate in the money pool as lenders and borrowers, and Exelon as a lender. Funding of, and borrowings from, the money pool are predicated on whether such funding results in mutual economic benefits to each of the participants, although Exelon is not permitted to be a net borrower from the money pool. Interest on borrowings is based on short-term market rates of interest, or specific borrowing rates if the funds are provided by external financing. There have been no material money pool transactions in 2002.

        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. The following table shows ComEd's securities ratings at December 31, 2002:

 
   Securities
   Moody's Investors
Service
   Standard & Poor's
   Fitch Ratings
ComEd   Senior secured debt   A3   A-   A-
    Commercial paper   P2   A2   F2

        A security rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency.

        Under PUHCA, 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 ComEd may not pay dividends out of paid-in capital after December 31, 2002 if its common equity is less than 30% of its total capitalization (including transitional trust notes). ComEd is

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precluded from lending or extending credit or indemnity to Exelon. At December 31, 2002, ComEd had retained earnings of $577 million.

Contractual Obligations and Commercial Commitments

        ComEd's contractual obligations as of December 31, 2002 representing cash obligations that are considered to be firm commitments are as follows:

 
    
   Payment due within
    
 
    
   Due after
5 Years
 
   Total
   1 Year
   2-3 Years
   4-5 Years
 
    
   (in millions)

    
    
Long-Term Debt   $ 6,024 (a) $ 750 (a) $ 1,383   $ 1,295   $ 2,596
Notes Payable     71     71     —     —     —
Operating Leases     135     22     38     32     43
Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding the Company's Subordinated Debt Securities     350     —     —     —     350
   
 
 
 
 
Total Contractual Obligations   $ 6,580   $ 843   $ 1,421   $ 1,327   $ 2,989
   
 
 
 
 
(a)
Includes $52 million of commercial paper classified as long-term debt under the provisions of SFAS No. 6, "Classification of Short-term Obligations to be Refinanced."

        On February 20, 2003, ComEd entered into separate agreements with Chicago and with Midwest Generation (Midwest Agreement). Under the terms of the agreement with Chicago, ComEd will pay Chicago $60 million over ten years to be relieved of a requirement, originally transferred to Midwest Generation upon the sale of ComEd's fossil stations in 1999, to build a 500-MW generation facility.

        See ITEM 8. Financial Statements and Supplementary Data—ComEd Notes to Consolidated Financial Statements for additional information about:

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        ComEd's commercial commitments as of December 31, 2002 representing commitments not recorded on the balance sheet but potentially triggered by future events, including financing arrangements to secure obligations of ComEd, are as follows:

 
    
   Expiration within
    
 
    
   After
5 Years
 
   Total
   1 Year
   2-3 Years
   4-5 Years
 
   (in millions)
Credit Facility(a)   $ 200   $ 200   $ —   $ —   $ —
Letters of Credit (non-debt)(b)     24     24     —     —     —
Letter of Credit (Long-term Debt)(c)     92     92     —     —     —
Insured Long-Term Debt(d)     100     —     —     —     100
Surety Bonds(e)     18     18     —     —     —
   
 
 
 
 
Total Commercial Commitments   $ 434   $ 334   $ —   $ —   $ 100
   
 
 
 
 
(a)
Credit Facility—ComEd, along with Exelon, PECO and Generation, maintain a $1.5 billion 364-day credit facility to support commercial paper issuances. ComEd has a $200 million sublimit under the credit facility. At December 31, 2002, there were no borrowings against the credit facility. Additionally, at December 31, 2002, ComEd had $123 million in outstanding commercial paper.

(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.

(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)
Surety Bonds—Guarantees issued related to contract and commercial surety bonds, excluding bid bonds.

        As part of a settlement agreement between ComEd and Chicago relating to ComEd's Chicago franchise agreement, ComEd and Chicago agreed to a revised combination of ongoing work under the franchise agreement and new initiatives that total approximately $1 billion in defined transmission and distribution expenditures by ComEd to improve electric service in Chicago, all of which has been expended through December 31, 2002.

Critical Accounting Estimates

        See ComEd, PECO and Generation—Critical Accounting Estimates above for a discussion of ComEd's Critical Accounting Estimates.

Business Outlook and the Challenges in Managing Our Business

        ComEd faces a number of challenges in achieving its vision and keeping its commitments to its customers and investors. ComEd may be significantly impacted by the end of its regulatory transition period in 2006. A significant challenge is that by existing law, after 2006, ComEd will not collect CTCs from customers who elect to receive generation services from alternative energy suppliers including the ComEd PPO. Additionally, the current bundled rate structure may be reset in a regulatory proceeding. It is difficult to predict the outcome of a potential regulatory proceeding to establish rates for 2007 and thereafter; nor is it possible to predict what changes may occur to the restructuring law in Illinois;

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however, ComEd is undertaking various efforts to mitigate the 2007 challenge. This and other challenges that will affect how ComEd manages its business are described below.

ComEd must comply with numerous regulatory requirements in managing its business, which affect costs and responsiveness to changing events and opportunities.

        ComEd's business is subject to regulation at the state and Federal levels. ComEd is regulated by the ICC which regulates the rates, terms and conditions of service; various business practices and transactions; financing; and transactions between ComEd and its affiliates. ComEd is also subject to regulation by the FERC, which regulates transmission rates and certain other aspects of its business. The regulations adopted by these state and Federal agencies affect the manner in which ComEd does business, its ability to undertake specified actions and the costs of its operations.

ComEd is involved in a number of regulatory proceedings as a part of the process of establishing the terms and rates for services.

        These regulatory proceedings typically involve multiple parties, including governmental bodies, consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases. The proceedings also involve various contested issues of law and fact and have a bearing upon the recovery of ComEd's costs through regulated rates. During the course of the proceedings, ComEd looks for opportunities to resolve contested issues in a manner that grant some certainty to all parties to the proceedings as to rates and energy costs.

        Delivery Services Rate Case.    ComEd is authorized to charge customers who purchase electricity from an alternative supplier for the use of its distribution system to deliver that electricity. These delivery service rates are set through proceedings before the ICC based upon, among other things, the operating costs associated with ComEd's distribution system and the capital investment that ComEd has made in its distribution system. In April 2002, the ICC issued an interim order that set delivery rates for ComEd's residential customers. The interim order was subject to an audit of test year (2000) expenditures, including capital expenditures. In October 2002, the ICC received the report on the audit of the test year expenditures by a consulting firm engaged by the ICC to perform the audit. The consulting firm recommended certain additional disallowances to test year expenditures and rate base levels. ComEd does not expect any change in delivery service rates to have a significant impact on results of operations in 2003. However, the estimated potential investment write-off, before income taxes, could be up to approximately $100 million if the ICC ultimately determines that all or some portion of ComEd's distribution plant is not recoverable through rates. In 2002, ComEd recorded a charge to earnings, before income taxes, of $12 million representing the estimated minimum probable exposure. ComEd is in negotiations with several parties to resolve the delivery service case.

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

        The Agreement addresses, among other things:

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

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

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

ComEd must maintain the availability and reliability of its delivery systems to meet customer expectations.

        Each year increases in both customers and the demand for energy requires expansion and reinforcement of delivery systems to increase capacity and maintain reliability. Failures of the equipment or facilities used in those delivery systems could potentially interrupt energy delivery services and related revenues, and increase repair expenses and capital expenditures. Such failures, including prolonged or repeated failures, also could affect customer satisfaction and may increase regulatory oversight and the level of ComEd's maintenance and capital expenditures. In addition, under Illinois law, ComEd can be required to pay damages to its customers in the event of extended outages affecting large numbers of its customers.

ComEd must manage its costs due to the rate and equity return limitations imposed on ComEd's revenues.

        Rate freezes in effect at ComEd currently limit the ability to recover increased expenses and the costs of investments in new transmission and distribution facilities. As a result, ComEd's future results of operations will depend on the ability of ComEd to deliver electricity in a cost-efficient manner, and to realize cost reductions to offset increased infrastructure investments and inflation.

        Rate limitations.    ComEd is subject to a legislatively mandated rate freeze on bundled retail rates that will remain effective until January 1, 2007.

        Equity return limitation.    ComEd is subject to a legislatively mandated cap on its return on common equity through the end of 2006. The cap is based on a two-year average of the U.S. Treasury long-term rates (25 years and above) plus 8.5%, and is compared to a two-year average return on ComEd's common equity. The legislation requires customer refunds equal to one-half of any excess earnings above the cap. ComEd is allowed to include regulatory asset amortization in the calculation of earnings. ComEd has not triggered the earnings sharing provision and currently does not expect to trigger the earnings sharing provision in the years 2003 through 2006. However, due to the historically low interest rates used in calculating the earnings cap, ComEd may be required to amortize additional regulatory assets.

ComEd has and will lose energy customers to other generation service providers, although it continues to provide delivery services and may have an obligation to provide generation service to those customers.

        The revenues of ComEd will vary because of customer choice of generation suppliers.    As a result of restructuring initiatives in Illinois, all of ComEd's retail electric customers can choose to purchase their generation supply from alternative suppliers. If customers do not choose an alternative generation supplier or take service under ComEd's PPO, ComEd is currently generally obligated to provide generation and delivery service to customers in its service territory at fixed rates, or in some instances, market-derived rates. In addition, customers who choose an alternative generation supplier may later return to ComEd, provided, however, that under Illinois law ComEd's obligation to provide generation

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may be eliminated over time if the ICC finds that competitive supply options are available to certain classes of customers. ComEd remains obligated to provide transmission and distribution service to all customers regardless of their generation supplier. To the extent that customers leave traditional bundled tariffs and select a different generation provider, ComEd revenues are likely to decline.

        At December 31, 2002, based on sales of energy approximately 27% of ComEd's small commercial and industrial (C&I) load and 61% of its large C&I load were purchasing their generation service from an alternative generation supplier or had chosen ComEd's PPO, a market-based price for energy. There are currently no certified alternative suppliers for the residential market in ComEd's service territory.

        The number of customers choosing alternative generation suppliers depends in part on the prices being offered by those suppliers relative to the fixed prices that ComEd is authorized to charge by the ICC. As a result of the right of customer choice of generation suppliers, ComEd anticipates that its revenues and gross margins could be variable.

ComEd continues to serve as the POLR for energy for all customers in its service territory.

        ComEd is required to make available generation service to all retail customers in its service territory, including customers that have taken energy from an alternative generation supplier. ComEd's customers can "switch," that is, they can choose an alternative generation supplier and then return to ComEd and then go back to an alternative supplier, and so on within limits. Because customers can switch, planning has a higher level of uncertainty than that traditionally experienced due to weather and the economy. In order to mitigate this risk with regard to its large commercial and industrial customers, on July 19, 2002, ComEd filed a request with the ICC to revise its POLR obligation in Illinois to be the back-up energy supplier to certain businesses. ComEd obtained permission from the ICC to limit the availability by June 2006 of Rate 6L for 370 of its largest energy customers. These are commercial and industrial customers, including heavy industrial plants, large office buildings, government facilities and a variety of other businesses with peak demands of at least three megawatts (MWs). ComEd's request affects a total of approximately 2,500 MWs. On November 14, 2002, the ICC allowed ComEd's request to go into effect as of June 2003. ComEd has no obligation to purchase power reserves to cover the load served by others. Presently, ComEd manages the POLR obligation through full requirements contracts with Generation, under which Generation is required to supply all of ComEd's power requirements. Because of the ability of customers to switch generation suppliers, there is uncertainty regarding the amount of ComEd load Generation must prepare for. The uncertainty increases Generation's costs. As a result, and in connection with its July 2002 ICC request, ComEd is discussing the POLR obligation issue with a number of parties including those who were parties to ComEd's rate request.

ComEd's long-term PPA provides a partial hedge to its customers' demand.

        Because the bundled rates ComEd charges its customers are frozen for several years as mentioned previously in the "Rate limitations" section, its ability to recover increased costs with increases in rates charged to these customers is limited. Therefore, to effectively manage its obligation to provide power to meet its customers' demand, ComEd has established power supply agreements with Generation that reduce exposure to the volatility of market prices through 2006. Market prices relative to ComEd's bundled rates still influence switching behavior among retail customers.

ComEd's business may be significantly impacted by the end of the regulatory transition period in 2006.

        Illinois electric utilities are allowed to collect CTCs from customers who choose an alternative supplier of electric generation service or choose a utility's PPO. CTCs were intended to assist electric utilities, such as ComEd, in recovering stranded costs that might not otherwise be recoverable in a fully

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competitive market. The CTC charge represents the difference between the competitive price of delivered energy (the sum of generation service at competitive prices and the regulated price of energy delivery) and recoveries under historical bundled rates, reduced by a mitigation factor. The CTC charges are updated annually. Over time, to facilitate the transition to a competitive market, the mitigation factor increases, thereby reducing the CTC charge. Under current law, ComEd will no longer collect CTCs at the end of 2006.

        In 2001, ComEd collected $110 million of CTC revenue, while in 2002, CTC revenue collected increased to $306 million due to the change in the competitive price of delivered electricity, primarily due to lower wholesale prices and more customers choosing alternative energy suppliers or the ComEd PPO. ComEd anticipates CTC revenues to be in the range of $350 million to $400 million for 2003 based on current assumptions about the competitive price of delivered energy and customers' choice of electric suppliers. Based on increasing mitigation factors, ComEd expects CTC revenues to decline in 2004 through 2006. In 2006, CTC revenues are estimated to be approximately $250 to $300 million annually. In addition, the CTC is dependent on the ICC's determination of the market price of electricity. In a proceeding before the ICC, various market participants, including alternative providers and large customers, have proposed modifications to the method for determining the market price that, if accepted, could have the effect of reducing the CTC. If the ICC issues orders making the Agreement effective, modification to the method for determining the market price of electricity would have the effect of reducing CTC revenues by an estimated $65 million to $70 million annually, effective in June 2003. Under the current restructuring statute, in 2007 this revenue will drop to zero. Through 2006, ComEd will continue to have a bundled service obligation, particularly to residential and small commercial customers. ComEd's current bundled service is generally provided under an all-inclusive rate that does not separately break out charges for energy generation service and energy delivery service, but charges a single set of prices. Much like the CTC collections, this revenue stream is authorized by the legislature through the transition period. After the transition ends in 2006, ComEd's bundled rates may be reset through a regulatory approval process, which may include traditional or innovative pricing, including performance-based incentives to ComEd.

        In order to address post-transition uncertainty, ComEd is constantly working with Illinois state and business community leadership to facilitate the development of a competitive electricity market while providing system reliability. This is particularly important as ComEd's costs to provide electricity to bundled residential and small commercial customers are capped by law at 110% of market. Transparent and liquid markets will help to minimize litigation over electricity prices and provide consumers assurance of equitable pricing. At the same time, ComEd is attempting to establish a regulatory framework for the post 2006 timeframe. To offset CTC revenue loss after 2006, ComEd is pursuing measures that would provide greater productivity, quality and innovation in the work practices across Exelon. Currently, it is difficult to predict the outcome of a potential regulatory proceeding to establish rates after 2006. Management believes that no one factor will solve the 2007 challenge, but that some combination of the components currently being worked on, together with other things Exelon and ComEd will do over the next four years, will address the 2007 challenge.

The ability to successfully manage the end of the transition period may affect ComEd's capital structure.

        ComEd has approximately $4.9 billion of goodwill recorded at December 31, 2002. This goodwill was recognized and recorded in connection with the Merger. Under GAAP, the goodwill will remain at its recorded amount unless it is determined to be impaired, which is based upon an analysis of ComEd's cash flows. If an impairment is determined at ComEd, the amount of the impaired goodwill will be written-off and expensed at ComEd. Presently, ComEd has sufficient cash flows to support the recorded amount of goodwill and thus, no impairment has been recorded. For a further discussion of this subject, see the Goodwill discussion within ComEd, PECO and Generation—Critical Accounting

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Estimates above. ComEd's cash flows include CTCs, which will cease at the end of 2006, unless there is a legislative or regulatory change and collections from traditional bundled customers at tariffed rates. Absent another source of revenues, to replace the loss of CTC revenue, all or a portion of the goodwill may become impaired. ComEd currently believes that there are a number of alternatives that could provide cash flows to support the goodwill. Under current regulations, a significant goodwill impairment may restrict ComEd's ability to pay dividends (see the Credit Issues section within Liquidity and Capital Resources above). ComEd is pursuing various solutions to address its ability to pay dividends if a significant goodwill impairment exists. However, based on Illinois legislation, goodwill impairments are excluded from determining whether or not the earnings cap amount has been met or exceeded (see the Equity return limitation discussion within Business Outlook and the Challenges in Managing Our Business above).

Weather affects electricity usage and, consequently, ComEd's results of operations.

        Temperatures above normal levels in the summer tend to further increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to further increase winter heating electricity demand and revenues. Because of seasonal pricing differentials, coupled with higher consumption levels, ComEd typically reports higher revenues in the third quarter of its fiscal year. However, extreme summer conditions or storms may stress ComEd's transmission and distribution systems, resulting in increased maintenance costs and limiting ComEd's ability to bring power in to meet peak customer demand. These extreme conditions may have detrimental effects on ComEd's operations.

Economic conditions and activity in ComEd's service territory directly affect the demand for electricity.

        Economic conditions and activity in ComEd's service territory directly affect the demand for electricity. Higher levels of development and business activity generally increase the number of customers and their use of energy. ComEd's business plan reflects an increase in output growth of 1.5% per year on a weather-normalized basis. However, there is continued economic uncertainty and ComEd is currently evaluating the impact of reduced economic activity on the 2003 growth rate. Recessionary economic conditions, and the associated reduced economic activity, may adversely affect ComEd's results of operations.

ComEd's business is affected by the restructuring of the energy industry.

        The electric utility industry in the United States is in transition. As a result of both legislative initiatives as well as competitive pressures, the industry has been moving from a fully regulated industry, consisting primarily of vertically integrated companies that combine generation, transmission and distribution, to a partially restructured industry, consisting of competitive wholesale generation markets and continued regulation of transmission and distribution. These developments have been somewhat uneven across the states as a result of the reaction to the problems experienced in California in 2000 and the more recently publicized problems of some energy companies. Illinois has adopted restructuring legislation designed to foster competition in the retail sale of electricity. A large number of states have not changed their regulatory structures.

        Regional Transmission Organizations / Standard Market Design.    To facilitate wholesale competition in the electric industry, FERC has required jurisdictional utilities to provide open access to their transmission systems. To foster the development of large regional wholesale markets, FERC issued Order 2000, encouraging the development of regional transmission organizations (RTOs) and the elimination of trade barriers between regions. FERC has also proposed a rulemaking to mandate a standard market design (SMD) for the wholesale markets. Order 2000 and the proposed SMD rule contemplate that the jurisdictional transmission owners in a region will turn over operating authority over their transmission facilities to an RTO or other independent entity for the purpose of providing

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open transmission access. As a result, the independent entity will become the provider of the transmission service and the transmission owners will recover their revenue requirements through the independent entity. The transmission owners will remain responsible for maintaining and physically operating their transmission facilities. The SMD rulemaking proposal would also requirethe independent entities to operate an organized bid-based wholesale market for those who wish to sell their generation through the market and to implement a financially-based system for dealing with congestion on transmission lines known as "locational marginal pricing" (LMP). FERC has also issued proposals to encourage RTO development, independent control of the transmission grid and expansion of the transmission grid by providing enhanced returns on equity for transmission assets.

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

Effective management of capital projects is important to ComEd's business.

        ComEd's business is capital intensive and requires significant investments in energy transmission and distribution facilities, and in other internal infrastructure projects.

        ComEd continues to make significant capital expenditures to improve the reliability of its transmission and distribution systems in order to provide a high level of service to its customers. ComEd expects that its capital expenditures will continue to exceed depreciation on its plant assets. ComEd's base rate freeze will generally preclude incremental rate recovery on any these incremental investments prior to January 1, 2007 (see the Rate limitations discussion within Business Outlook and the Challenges in Managing Our Business above).

Capital Markets / Financing Environment

        In order to expand ComEd's operations and to meet the needs of current and future customers, ComEd invests in its business. The ability to finance ComEd's business and other necessary expenditures is affected by the capital-intensive nature of ComEd's operations and ComEd's current and future credit ratings. The capital markets also affect Exelon's benefit plan assets. Further discussions of ComEd's liquidity position can be found in the Liquidity and Capital Resources section above.

The ability to grow ComEd's business is affected by the ability to finance capital projects.

        ComEd's business requires considerable capital resources. When necessary, ComEd secures funds from external sources by issuing commercial paper and, as required, long-term debt securities. ComEd actively manages its exposure to changes in interest rates through interest-rate swap transactions and its balance of fixed- and floating-rate instruments. Management currently anticipates primarily using internally generated cash flows and short-term financing through commercial paper to fund operations as well as long-term external financing sources to fund capital requirements as the needs and opportunities arise. The ability to arrange debt financing, to refinance current maturities and early retirements of debt, and the costs of issuing new debt are dependent on:

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ComEd's credit ratings influence its ability to raise capital.

        ComEd has investment grade ratings and has been successful in raising capital, which has been used to further its business initiatives. Failure to maintain investment grade ratings would require ComEd to incur higher financing costs.

Equity market performance affects Exelon's benefit plan asset values.

        The sharp decline in the equity markets since the third quarter of 2000 has reduced the value of the assets held in trusts to satisfy the obligations of pension and postretirement benefit plans. If the markets continue to decline, Exelon may have higher funding requirements and pension and other postretirement benefit expense. Exelon will continue to manage the assets in the pension and postretirement benefit plans in order to achieve the best return possible in conjunction with Exelon's overall risk management practices and diversified approach to investment. Please refer to the Critical Accounting Estimates section that more fully describes the quantitative financial statement effects of changes in the equity markets on the benefit plan assets.

ComEd's results of operations can be affected by inflation.

        Inflation affects ComEd through increased operating costs and increased capital costs for transmission and distribution plant. As a result of the rate freezes 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.

Other

ComEd may incur substantial cost to fulfill its obligations related to environmental matters.

        ComEd's business is subject to extensive environmental regulation by local, state and Federal authorities. These laws and regulations affect the manner in which ComEd conducts its operations and make its capital expenditures. ComEd is subject to liability under these laws for the costs of remediating environmental contamination of property now or formerly owned by ComEd and of property contaminated by hazardous substances ComEd generated. Management believes that it has a responsible environmental management and compliance program; however, ComEd has incurred and expects to incur significant costs related to environmental compliance and site remediation and clean-up. Remediation activities associated with manufactured gas plant operations conducted by predecessor companies will be one source of such costs. Also, 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, 2002, ComEd's reserve for environmental investigation and remediation costs was $101 million, exclusive of decommissioning liabilities. ComEd has accrued and will continue to accrue amounts that management believes are prudent to cover these environmental liabilities, but ComEd cannot predict with any certainty whether these amounts will be sufficient to cover ComEd's environmental liabilities. Management cannot predict whether ComEd will incur other significant

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liabilities for any additional investigation and remediation costs at additional sites not currently identified by ComEd, environmental agencies or others, or whether such costs will be recoverable from third parties.

ComEd's financial performance is affected by its ability to manage costs for security and liability insurance.

        Security.    In connection with the events of September 11, 2001, the electric industry has developed additional security guidelines. The electric industry, through the North American Electric Reliability Council (NERC), developed physical security guidelines, which were accepted by the U.S. Department of Energy. In 2003, FERC is expected to issue minimum standards to safeguard the electric grid system control. These standards are expected to be effective in 2004 and fully implemented by January 2005. Exelon participated in the development of these guidelines and ComEd is using them as a model for its security program.

        Insurance.    ComEd, through Exelon, 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. Exelon is self-insured to the extent that any losses may exceed the amount of insurance maintained.

The possibility of attack or war may adversely affect ComEd's results of operations, future growth and ability to raise capital.

        Any military strikes or sustained military campaign may affect ComEd's operations in unpredictable ways, such as increased security measures and disruptions of fuel supplies and markets, particularly oil. Just the possibility that infrastructure facilities, such as electric generation, transmission and distribution facilities, would be direct targets of, or indirect casualties of, an act of terror or war may affect ComEd's operations. War and the possibility of war may have an adverse effect on the economy in general. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect ComEd's revenues or restrict ComEd's future growth. Instability in the financial markets as a result of war may affect ComEd's ability to raise capital.

The introduction of new technologies could increase competition in ComEd's market.

        While demand for electricity is generally increasing throughout the United States, the rate of construction and development of new, more efficient, electric generation facilities and distribution methodologies may exceed increases in demand in some regional electric markets. The introduction of new technologies could increase competition, which could lower prices and have an adverse effect on ComEd's results of operations or financial condition.

New Accounting Pronouncements

        See ComEd, PECO and Generation—New Accounting Pronouncements above for a discussion of new accounting pronouncements.

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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.

Results of Operations

Year Ended December 31, 2002 Compared To Year Ended December 31, 2001

Significant Operating Trends—PECO

 
   2002
   2001
   Variance
   % Change
  
OPERATING REVENUES   $ 4,333   $ 3,965   $ 368   9.3 %

OPERATING EXPENSES
 
 
 
 
 
 
 
 
 
 
 
 
  Purchased Power     1,669     1,352     317   23.4 %
  Fuel     348     450     (102 ) (22.7 %)
  Operating and Maintenance     523     587     (64 ) (10.9 %)
  Depreciation and Amortization     456     416     40   9.6 %
  Taxes Other Than Income     244     161     83   51.6 %
   
 
 
 
 
    Total Operating Expense     3,240     2,966     274   9.2 %
   
 
 
 
 
OPERATING INCOME     1,093     999     94   9.4 %
   
 
 
 
 

OTHER INCOME AND DEDUCTIONS
 
 
 
 
 
 
 
 
 
 
 
 
  Interest Expense     (370 )   (413 )   43   (10.4 %)
  Distributions on Company-Obligated
Mandatorily Redeemable
Preferred Securities of a Partnership
which holds Solely Subordinated Debentures of the Company		     (10 )   (10 )   —   —  
  Other, Net     32     46     (14 ) (30.4 %)
   
 
 
 
 
    Total Other Income and Deductions     (348 )   (377 )   29   (7.7 %)
   
 
 
 
 
INCOME BEFORE INCOME TAXES     745     622     123   19.8 %

INCOME TAXES
 
 
259
 
 
197
 
 
62
 
31.5
%
   
 
 
 
 
NET INCOME     486     425     61   14.4 %
Preferred Stock Dividends     (8 )   (10 )   2   (20.0 %)
   
 
 
 
 

NET INCOME ON COMMON STOCK
 
$
478
 
$
415
 
$
63
 
15.2
%
   
 
 
 
 

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Net Income

        Net income on common stock increased $63 million, or 15%, in 2002 as compared to 2001. The increase was a result of higher sales volume, favorable rate adjustments, lower operating and maintenance expense and lower interest expense on debt partially offset by increased taxes other than income and increased depreciation and amortization expense.

Operating Revenue

        PECO's electric sales statistics and revenue detail are as follows:

Retail Deliveries—(in GWhs)
   2002
   2001
   Variance
   % Change
  
Bundled Deliveries(1)                  
Residential   10,365   8,073   2,292   28.4 %
Small Commercial & Industrial   7,606   5,998   1,608   26.8 %
Large Commercial & Industrial   14,766   12,960   1,806   13.9 %
Public Authorities & Electric Railroads   852   765   87   11.4 %
   
 
 
 
 
    33,589   27,796   5,793   20.8 %
   
 
 
 
 
Unbundled Deliveries(2)                  
Residential   1,971   3,105   (1,134 ) (36.5 %)
Small Commercial & Industrial   415   1,606   (1,191 ) (74.2 %)
Large Commercial & Industrial   557   2,352   (1,795 ) (76.3 %)
Public Authorities & Electric Railroads   —   7   (7 ) (100.0 %)
   
 
 
 
 
    2,943   7,070   (4,127 ) (58.4 %)
   
 
 
 
 
Total Retail Deliveries   36,532   34,866   1,666   4.8 %
   
 
 
 
 
(1)
Bundled service reflects deliveries to customers taking electric service under tariffed rates.

(2)
Unbundled service reflects customers electing to receive electric generation service from an alternative energy supplier.

Electric Revenue
   2002
   2001
   Variance
   % Change
  
Bundled Revenue(1)                        
Residential   $ 1,338   $ 1,028   $ 310   30.2 %
Small Commercial & Industrial     865     682     183   26.8 %
Large Commercial & Industrial     1,086     929     157   16.9 %
Public Authorities & Electric Railroads     79     72     7   9.7 %
   
 
 
 
 
      3,368     2,711     657   24.2 %
   
 
 
 
 
Unbundled Revenue(2)                        
Residential     145     235     (90 ) (38.3 %)
Small Commercial & Industrial     21     81     (60 ) (74.1 %)
Large Commercial & Industrial     16     64     (48 ) (75.0 %)
Public Authorities & Electric Railroads     —     1     (1 ) (100.0 %)
   
 
 
 
 
      182     381     (199 ) (52.2 %)
   
 
 
 
 
Total Electric Retail Revenues     3,550     3,092     458   14.8 %
Wholesale and Miscellaneous Revenue(3)     234     219     15   6.8 %
   
 
 
 
 
Total Electric Revenue   $ 3,784   $ 3,311   $ 473   14.3 %
   
 
 
 
 
(1)
Bundled revenue reflects revenue from customers taking electric service under tariffed rates, which includes the cost of energy, the delivery cost of the transmission and the distribution of the energy and a CTC charge.

(2)
Unbundled revenue reflects revenue from customers electing to receive generation from an alternative supplier, which include a distribution charge and a CTC charge.

93

(3)
Wholesale and miscellaneous revenues include transmission revenue and other wholesale energy sales.

        The changes in electric retail revenues in 2002, as compared to 2001, were attributable to the following:

 
   Variance
  
Customer Choice   $ 226  
Volume     133  
Weather     63  
Rate Changes     45  
Other Effects     (9 )
   
 
Electric Retail Revenue   $ 458  
   
 
•
Customer Choice.  All PECO customers have the 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.
•
Volume.  Exclusive of weather impacts, higher delivery volume increased PECO's revenue $133 million compared to 2001, primarily related to increases in the residential and small commercial and industrial customer classes.

•
Weather.  The weather impact was favorable compared to the prior year as a result of warmer summer weather. Cooling degree-days increased 15% in 2002 compared to 2001. Heating degree-days increased 1% in 2002 compared to 2001.

•
Rate Changes.  The increase in revenues attributable to rate changes primarily reflects the expiration of a 6% reduction in PECO's electric rates during the first quarter of 2001 and a $50 million increase as a result of the increase in the gross receipts tax rate effective January 1, 2002. These increases are partially offset by the timing of a $60 million rate reduction in effect for 2001 and 2002.
•
Other Effects.  Other items affecting revenue include an $11 million settlement of CTC's by a large customer in the first quarter of 2001.

94

        PECO's gas sales statistics and revenue detail are as follows:

 
   2002
   2001
   Variance
  
Deliveries in millions of cubic feet (mmcf)     85,545     81,528     4,017  
Revenue   $ 549   $ 654   $ (105 )

        The changes in gas revenue for 2002, as compared to 2001, were attributable to the following:

 
   Variance
  
Rate Changes   $ (108 )
Weather     2  
Volume     1  
   
 
Gas Revenue   $ (105 )
   
 
•
Rate Changes.  The unfavorable variance in rates is attributable to an adjustment of the purchased gas cost recovery by the PUC in December 2001. The average rate per million cubic feet for 2002 was 20% lower than in 2001. PECO's gas rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers 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. Effective December 1, 2002, the PUC approved a reduction in the purchased gas adjustment of 4.5%.

•
Weather.  The weather impact was favorable, as a result of colder weather in 2002, as compared to 2001. Heating degree-days in PECO's service territory increased 1% in 2002 compared to 2001.

•
Volume.  Exclusive of weather impacts, higher delivery volume increased revenue by $1 million in 2002 compared to 2001. Total deliveries to customers increased 5% in 2002 compared to 2001, primarily as a result of customer growth and higher transportation volumes

Purchased Power

        Purchased power expense in 2002 increased $317 million as compared to 2001. The increase in purchased power expense was primarily attributable to $210 million from customers in Pennsylvania selecting or returning to PECO as their electric generation supplier, higher PJM ancillary charges of $41 million, $38 million from higher delivery volume primarily related to electric sales and $28 million as a result of favorable weather conditions.

Fuel

        Fuel expense in 2002 decreased $102 million as compared to 2001. This decrease was primarily attributable to a $108 million decrease from lower gas prices.

Operating and Maintenance

        O&M expense in 2002 decreased $64 million, or 11%, as compared to 2001. The decrease in O&M expense was primarily attributable to a $23 million reduction in the allowance for the uncollectible accounts during 2002, and $6 million related to lower corporate allocations. The decrease is also attributable to $18 million of employee severance costs associated with the Merger, $12 million of incremental costs related to two storms, $7 million attributable to customer choice and $5 million associated with a write-off of excess and obsolete inventory, all of which occurred in 2001. These decreases are partially offset by $12 million related to additional costs associated with the deployment of automated meter reading technology during 2002.

95


Depreciation and Amortization

        Depreciation and amortization expense in 2002 increased $40 million, or 10%, as compared to 2001 as follows:

 
   2002
   2001
   Variance
   % Change
  
Competitive Transition Charge Amortization   $ 308   $ 271   $ 37   13.7 %
Depreciation Expense     125     119     6   5.0 %
Other Amortization Expense     23     26     (3 ) (11.5 %)
   
 
 
 
 
Total Depreciation and Amortization   $ 456   $ 416   $ 40   9.6 %
   
 
 
 
 

        The increase was primarily attributable to $37 million of additional amortization of PECO's CTC and an increase of $6 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 in 2002 increased $83 million, or 52%, as compared to 2001. The increase was primarily attributable to $72 million of additional gross receipts tax related to additional revenues and an increase in the gross receipts tax rate on electric revenue effective January 1, 2002. The increase was also attributable to $15 million related to an additional assessment of real estate taxes in 2002. These increases were partially offset by a decrease of $4 million for state sales and use tax in 2002.

Interest Charges

        Interest charges consist of interest expense and distributions on Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS). Interest charges decreased $43 million, or 10%, in 2002 as compared to 2001. The decrease was primarily attributable to lower interest expense on long-term debt of $35 million as a result of less outstanding debt and refinancing of existing debt at lower interest rates, and $8 million in interest expense on a loan from ComEd in 2001.

Other Income and Deductions

        Other income and deductions excluding interest charges decreased $14 million, or 30%, in, 2002 as compared to 2001. The decrease in other income and deductions was primarily attributable to intercompany interest income of $10 million, a gain on the settlement of an interest rate swap of $6 million and the favorable settlement of a customer contract of $3 million, all of which occurred in 2001.

Income Taxes

        The effective tax rate was 34.8% in 2002 as compared to 31.7% in 2001. The increase in the effective tax rate was primarily attributable to an unfavorable tax adjustments recorded in 2002.

Preferred Stock Dividends

        Preferred stock dividends in 2002 were consistent as compared to 2001.

96


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

Summary Financial Information—PECO

 
    
    
   Components of Variance
  
 
   2001
   2000
   Restructuring
Impact
   Normal
Operations
   Total
  
OPERATING REVENUES   $ 3,965   $ 5,950   $ (2,577 ) $ 592   $ (1,985 )
 
Purchased Power and Fuel
 
 
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 )
   
 
 
 
 
 

OTHER INCOME AND DEDUCTIONS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Expense     (413 )   (463 )   48     2     50  
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 AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE     622     751     (21 )   (108 )   (129 )
INCOME TAXES     197     268     26     (97 )   (71 )
   
 
 
 
 
 
NET INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE     425     483     (47 )   (11 )   (58 )
CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE (net of income taxes)     —     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.

97


Operating Revenues

        PECO's electric sales statistics and revenue detail are as follows:

Retail Deliveries—(in GWhs)
   2001
   2000
   Variance
   % Change
  
Bundled Deliveries(1)                  
Residential   8,073   9,325   (1,252 ) (13.4 %)
Small Commercial & Industrial   5,998   3,918   2,080   53.1 %
Large Commercial & Industrial   12,960   8,292   4,668   56.3 %
Public Authorities & Electric Railroads   765   479   286   59.7 %
   
 
 
 
 
    27,796   22,014   5,782   26.3 %
   
 
 
 
 
Unbundled Deliveries(2)                  
Residential   3,105   1,986   1,119   56.3 %
Small Commercial & Industrial   1,606   3,550   (1,944 ) (54.8 %)
Large Commercial & Industrial   2,352   7,404   (5,052 ) (68.2 %)
Public Authorities & Electric Railroads   7   301   (294 ) (97.7 %)
   
 
 
 
 
    7,070   13,241   (6,171 ) (46.6 %)
   
 
 
 
 
Total Retail Deliveries   34,866   35,255   (389 ) (1.1 %)
   
 
 
 
 
(1)
Bundled service reflects deliveries to customers taking electric service under tariffed rates.

(2)
Unbundled service reflects customers electing to receive electric generation service from an alternative energy supplier.

Electric Revenue
   2001
   2000
   Variance
   % Change
  
Bundled Revenue(1)                        
Residential   $ 1,028   $ 1,113   $ (85 ) (7.6 %)
Small Commercial & Industrial     682     422     260   61.6 %
Large Commercial & Industrial     929     532     397   74.6 %
Public Authorities & Electric Railroads     72     47     25   53.2 %
   
 
 
 
 
      2,711     2,114     597   28.2 %
   
 
 
 
 
Unbundled Revenue(2)                        
Residential     235     135     100   74.1 %
Small Commercial & Industrial     81     154     (73 ) (47.4 %)
Large Commercial & Industrial     64     180     (116 ) (64.4 %)
Public Authorities & Electric Railroads     1     11     (10 ) (90.9 %)
   
 
 
 
 
      381     480     (99 ) (20.6 %)
   
 
 
 
 
Total Electric Retail Revenues     3,092     2,594     498   19.2 %
Wholesale and Miscellaneous Revenue(3)     219     247     (28 ) (11.3 %)
   
 
 
 
 
Total Electric Revenue   $ 3,311   $ 2,841   $ 470   16.5 %
   
 
 
 
 
(1)
Bundled revenue reflects revenue from 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 charge.

(2)
Unbundled revenue reflects revenue from customers electing to receive generation from an alternative energy supplier, which include a distribution charge and a CTC charge.

98

(3)
Wholesale and miscellaneous revenues include transmission revenue and other wholesale energy sales.

        The changes in electric retail revenues for 2001, as compared to 2000, were attributable to the following:

 
   Variance
  
Customer Choice   $ 276  
Rate Changes     241  
Weather     (5 )
Other Effects     (14 )
   
 
Retail Revenue   $ 498  
   
 
•
Customer Choice.  All PECO customers had the choice to purchase energy from other suppliers throughout 2001. 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 alternative supplier continue to pay CTCs.

•
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 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:

•
Volume.  Exclusive of weather impacts, lower delivery volume affected PECO's revenue by $21 million compared to 2000 primarily related to increases in the residential and small commercial and industrial customer classes.

•
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 CTCs by a large customer in the first quarter of 2001.

        PECO's gas sales statistics and revenue detail are as follows:

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

99

        The changes in gas revenue for 2001, as compared to 2000, were attributable to the following:

 
   Variance
  
Rate Changes   $ 174  
Weather     (38 )
Volume     (14 )
   
 
Gas Revenue   $ 122  
   
 
•
Rate Changes.  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.

•
Weather.  The unfavorable weather impact is attributable to warmer winter weather conditions. Heating degree-days decreased 12% in 2001 compared to 2000.

•
Volume.  Exclusive of weather impacts, lower delivery volume affected revenue by $14 million compared to 2000. Total volume of sales to retail customers decreased 11% compared to 2000, primarily as a result of slower economic conditions in 2001 offset by customer growth.

Purchased Power and Fuel

        Purchased power and fuel expense for 2001 increased $468 million, or 35%, as compared to the same 2000 period, excluding the effects of the restructuring. The increase in purchased power and fuel 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

        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 associated with the Merger, $17 million as a result of higher administrative and general costs for functions previously performed at Corporate, $14 million related to the deployment of automated meter reading technology 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 approval and settlement costs, and settlement of compensation arrangements. Employee costs represent estimated severance payments and pension and postretirement benefits provided under Exelon's merger separation plan for 642 eligible PECO employees who were 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 of the Notes to Consolidated Financial Statements.

100


Depreciation and Amortization

        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 COMRPS. Interest charges for 2001 were consistent as compared to 2000.

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, the reduced impact of investment tax credit amortization and other tax adjustments recorded in 2001.

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.

101


Liquidity and Capital Resources

        PECO's business is capital intensive and requires considerable 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 general business conditions, as well as that of the utility industry in general. Capital resources are used primarily to fund PECO's capital requirements, including construction, repayments of maturing debt and payment of dividends.

Cash Flows from Operating Activities

        Cash flows provided by operations in 2002 were $880 million compared to $938 million in 2001. The decrease in cash flows from operating activities was primarily attributable to a $79 million decrease in other operating activities primarily a result of the change in pension obligation, a $26 million decrease in working capital, a $26 million decrease in deferred income taxes and a $23 million decrease in the provision for uncollectible accounts, partially offset by a $61 million increase in net income and a $37 million increase in CTC amortization. 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 operating cost reductions, 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.

        PECO participates in Exelon's defined benefit pension plans. Exelon's plans currently meet the minimum funding requirements of the Employment Retirement Income Security Act of 1974; however Exelon made a $150 million discretionary plan contribution in 2002, none of which was funded by PECO. Exelon also expects to make a discretionary plan contribution of $300 million to $350 million in 2003.

Cash Flows from Investing Activities

        Cash flows used in investing activities in 2002 were $252 million compared to $241 million in 2001. The increase in cash flows used in investing activities was primarily attributable to an increase in capital expenditures. PECO's investing activities during 2002 were funded primarily by operating activities.

        PECO's projected capital expenditures for 2003 are $270 million. Approximately one half of the budgeted 2003 expenditures are for capital additions to support customer and load growth and the remainder for additions and upgrades to 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 in 2002 were $597 million compared to $683 million in 2001. Cash flows used in financing activities are primarily attributable to debt service and payment of dividends to Exelon. In 2002, PECO issued $225 million of First and Refunding Mortgage Bonds. The proceeds of these bonds were used to repay commercial paper that PECO used to pay $222 million of First and Refunding Mortgage Bonds at maturity. Also in 2002, PECO made principal payments of $326 million on transition bonds and had net issuances of $200 million of commercial paper. PECO paid a $340 million dividend to Exelon during 2002 compared to a $342 million dividend in 2001.

102


Credit Issues

        PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from Exelon's intercompany money pool. PECO, along with Exelon, ComEd and Generation, participates in a $1.5 billion unsecured 364-day revolving credit facility with a group of banks. The credit facility became effective November 22, 2002 and includes a term-out option that allows any outstanding borrowings at the end of the revolving credit period to be repaid on November 21, 2004. Exelon may increase or decrease the sublimits of each of the participants upon written notification to the banks. As of December 31, 2002, PECO's sublimit was $400 million. The credit facility is used by PECO principally to support its commercial paper program. At December 31, 2002, PECO's Consolidated Balance Sheet reflects $200 million in commercial paper outstanding.

        For 2002, the average interest rate on notes payable was approximately 1.51%. Certain of the credit agreements to which PECO is a party require it to maintain a cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratio excludes revenues and interest expenses attributed to securitization debt, certain changes in working capital and distributions on preferred securities of subsidiaries. PECO's threshold for the ratio reflected in the credit agreement cannot be less than 2.25 to 1 for the twelve-month period ended December 31, 2002. At December 31, 2002, PECO was in compliance with the credit agreement thresholds.

        At December 31, 2002, PECO's capital structure, excluding the deduction from shareholders' equity of the $1.8 billion receivable from Exelon, consisted of 28% common stock, 2% notes payable, 3% preferred securities and COMRPS, and 67% long-term debt. Long-term debt included $4.3 billion of transition bonds issued by PECO Energy Transition Trust representing 50% of capitalization.

        To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany utility money pool. Participation in the money pool is subject to authorization by Exelon's corporate treasurer. ComEd and its subsidiary Commonwealth Edison of Indiana, Inc., PECO, Generation and BSC may participate in the money pool as lenders and borrowers, and Exelon as a lender. Funding of, and borrowings from, the money pool are predicated on whether such funding results in mutual economic benefits to each of the participants, although Exelon is not permitted to be a net borrower from the money pool. Interest on borrowings is based on short-term market rates of interest, or, if from an external source, specific borrowing rates. There were no material money pool transactions in 2002.

        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 certain bank credit facilities. The following table shows PECO's securities ratings at December 31, 2002:

 
   Securities
   Moody's Investors
Service
   Standard & Poor's
   Fitch
Ratings
PECO   Senior secured debt   A2   A   A
    Commercial paper   P1   A2   F1

        A security rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency.

        Under PUHCA, PECO is precluded from lending or extending credit or indemnity to Exelon and can pay dividends only from retained or current earnings. At December 31, 2002, PECO had retained earnings of $401 million.

103


Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations

        PECO's contractual obligations as of December 31, 2002 representing cash obligations that are considered to be firm commitments are as follows:

 
    
   Payment due within
    
 
    
   Due after
5 Years
 
   Total
   1 Year
   2-3 Years
   4-5 Years
 
   (in millions)
Long-Term Debt   $ 5,644   $ 689   $ 883   $ 1,141   $ 2,931
Notes Payable     200     200     —     —     —
COMRPS     128     —     —     —     128
Operating Leases     20     5     7     5     3
   
 
 
 
 
Total Contractual Obligations   $ 5,992   $ 894   $ 890   $ 1,146   $ 3,062
   
 
 
 
 

        See ITEM 8. Financial Statements and Supplementary Data—PECO, Notes to Consolidated Financial Statements for additional information about:

        PECO's commercial commitments as of December 31, 2002 representing commitments not recorded on the balance sheet but potentially 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
5 Years
 
   Total
   1 Year
   2-3 Years
   4-5 Years
 
   (in millions)
Credit Facility(a)   $ 400   $ 400   $ —   $ —   $ —
Letters of Credit (non-debt)(b)     29     29     —     —     —
Letter of Credit (Long-term Debt)(c)     17     17     —     —     —
Insured Long-Term Debt(d)     154     —     —     —     154
Surety Bonds(e)     46     46     —     —     —
   
 
 
 
 
Total Commercial Commitments   $ 646   $ 492   $ —   $ —   $ 154
   
 
 
 
 
(a)
Credit Facility—PECO, along with Exelon, ComEd and Generation, maintain a $1.5 billion 364-day credit facility to support commercial paper issuances. PECO has a $400 million sublimit under the credit facility. At December 31, 2002, there are no borrowings against the credit facility. Additionally, at December 31, 2002, PECO had $200 million in outstanding commercial paper.

(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.

104

(e)
Surety bonds—Guarantees issued related to contract and commercial surety bonds, excluding bid bonds.

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. PECO entered into this agreement to diversify its funding sources at favorable floating interest rates. At December 31, 2002, PECO had sold a $225 million interest in accounts receivable, consisting of a $164 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 $61 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 8 of the 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 cash, which would otherwise be received by PECO under this program, to be held in escrow until the requirement is met. At December 31, 2002 and 2001, PECO met this requirement.

Critical Accounting Estimates

        See ComEd, PECO and Generation—Critical Accounting Estimates above for a discussion of PECO's critical accounting estimates.

Business Outlook and the Challenges in Managing Our Business

        PECO faces a number of challenges in achieving its vision and keeping its commitments to its customers and investors. These challenges that will affect how PECO manages its business are described below.

PECO must comply with numerous regulatory requirements in managing its business, which affect costs and responsiveness to changing events and opportunities.

        PECO is subject to regulation at the state and Federal levels. PECO is regulated by the PUC, which regulates the rates, terms and conditions of service; various business practices and transactions; financing; and transactions between PECO and its affiliates. PECO is also subject to regulation by FERC, which regulates transmission rates, certain other aspects of its business and gas pipelines. The regulations adopted by these state and Federal agencies affect the manner in which PECO does business, its ability to undertake specified actions and the costs of its operations.

PECO is involved in a number of regulatory proceedings as a part of the process of establishing the terms and rates for services.

        These regulatory proceedings typically involve multiple parties, including governmental bodies, consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases. The proceedings also involve various contested issues of law and fact and have a bearing upon the recovery of PECO's costs through regulated rates. During the course of the proceedings, PECO looks for opportunities to resolve contested issues in a manner that grant some certainty to all parties to the proceedings as to rates and energy costs.

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PECO must maintain the availability and reliability of its delivery systems to meet customer expectations.

        Each year, increases in both customers and the demand for energy require expansion and reinforcement of delivery systems to increase capacity and maintain reliability. Failures of the equipment or facilities used in those delivery systems could potentially interrupt energy delivery services and related revenues, and increase repair expenses and capital expenditures. Such failures, including prolonged or repeated failures, also could affect customer satisfaction and may increase regulatory oversight and the level of PECO's maintenance and capital expenditures.

PECO must manage its costs due to the rate caps imposed on PECO.

        Rate caps in effect at PECO currently limit PECO's ability to recover increased expenses and the costs of investments in new transmission and distribution facilities. PECO is subject to agreed-upon rate reductions of $200 million, in aggregate, for the period 2002 through 2005 and caps (subject to limited exceptions for significant increases in Federal or state income taxes or other significant changes in law or regulation that do not allow PECO to earn a fair rate of return) on its transmission and distribution rates through December 31, 2006 as a result of settlements previously reached with the PUC. As a result, PECO's future results of operations will depend on the ability of PECO to deliver electricity and natural gas, in a cost-efficient manner, and to realize cost reductions to offset increased infrastructure investments and inflation.

PECO has lost and will lose energy customers to other generation service providers, although it continues to provide delivery services and may have an obligation to provide generation service to those customers.

        The revenues of PECO will vary because of customer choice of generation suppliers. As a result of restructuring initiatives in Pennsylvania, all of PECO's retail electric customers can choose to purchase their generation supply from alternative suppliers. If customers do not choose an alternative generation supplier PECO, is currently generally obligated to provide generation and delivery service to customers in its service territory at fixed rates. In addition, customers who choose an alternative generation supplier may later return to PECO. PECO remains obligated to provide transmission and distribution service to all customers regardless of their generation supplier. To the extent that customers leave traditional bundled tariffs and select a different generation provider, PECO's revenues are likely to decline.

        At December 31, 2002, approximately 10% of PECO's small C&I load, 7% of its large C&I load and 21% of its residential load were purchasing their generation service from an alternative electric generation supplier.

        PECO's Electric Restructuring Settlement established MST for residential and commercial customers such that if, on January 1, 2003, 50% of PECO's residential and commercial customers (by number of customers for residential and small commercial classes, and by load for large commercial classes) are not obtaining generation service from alternative generation suppliers, then non-shopping customers, up to the MSTs level, will be randomly assigned to alternative generation suppliers. The assigned customers have the right, at any time, to return to PECO or to switch to another supplier.

        The number of customers choosing alternative generation suppliers depends in part on the prices being offered by those suppliers relative to the fixed prices that PECO is authorized to charge by the PUC.

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PECO continues to serve as the POLR for energy for all customers in its service territory.

        PECO is required to make available generation service to all retail customers in its service territory, including customers that have taken energy from an alternative generation supplier. PECO customers can "switch," that is, they can choose an alternative generation supplier and then return to PECO and then go back to an alternative supplier, and so on, within limits. Because customers can switch, planning for PECO has a higher level of uncertainty than that traditionally experienced due to weather and the economy. Presently, PECO manages the POLR obligation through a full requirements contract with Generation, under which Generation supplies PECO's power requirements. Because of the ability of customers to switch generation suppliers, there is uncertainty regarding the amount of PECO load that Generation must prepare for.

PECO's long-term PPA provides a hedge to its customers' demand.

        Because the bundled rates PECO charges its customers are capped through 2010, as mentioned previously in the "Rate limitations" section, its ability to recover increased costs with increases in rates charged to these customers is limited. Therefore, to effectively manage its obligation to provide power to meet its customers' demand, PECO has established power supply agreements with Generation that reduce exposure to the volatility of market prices through 2010. Market prices relative to PECO's bundled rates still influence switching behavior among retail customers.

PECO's business may be significantly impacted by the end of the PECO regulatory transition period in 2010.

        In Pennsylvania, as a mechanism for utilities to recover their allowed stranded costs, the Pennsylvania Electricity Generation Customer Choice and Competition Act (Competition Act) provides for the imposition and collection of non-bypassable CTCs on customers' bills. CTCs are assessed to and collected from all 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 are assessed regardless of whether such customer purchases electricity from the utility or an alternative electric generation supplier. The Competition Act provides, however, that the utility's right to collect CTCs is contingent on the continued operation, at reasonable availability levels, of the assets for which the stranded costs are being recovered, except where continued operation is no longer cost efficient because of the transition to a competitive market.

        PECO has been authorized by the PUC to recover stranded costs of $5.3 billion ($4.6 billion of unamortized costs at December 31, 2002) 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 revenues. In 2002, revenue attributable to stranded cost recovery was $850 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 2002 was $308 million and will increase to $879 million by 2010. Thus, PECO's results will be adversely affected over the remaining period ending December 31, 2010 by the reduction in the unamortized balance of stranded costs and therefore the return received on that unamortized balance.

Weather affects electricity and gas usage and, consequently, PECO's results of operations.

        Temperatures above normal levels in the summer tend to further increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to further increase winter heating electricity and gas demand and revenues. Because of seasonal pricing

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differentials, coupled with higher consumption levels, PECO typically reports higher revenues in the third quarter. Extreme summer conditions or storms may stress PECO's transmission and distribution systems, resulting in increased maintenance costs and limiting its ability to bring power in to meet peak customer demand. These extreme conditions may have detrimental effects on PECO's operations.

Economic conditions and activity in PECO's service territory directly affect the demand for electricity.

        Higher levels of development and business activity generally increase the number of customers and their use of energy. Sales growth on an annual basis is expected to be 0.6% in PECO's service territory. In the long-term, output growth for electricity is expected to be 0.6% per year. However, there is continued economic uncertainty. Recessionary economic conditions, and the associated reduced economic activity, may adversely affect PECO's results of operations.

Effective management of capital projects is important to PECO's business.

        PECO's business is capital intensive and requires significant investments in energy transmission and distribution facilities, and in other internal infrastructure projects.

        PECO continues to make significant capital expenditures to improve the reliability of its transmission and distribution systems in order to provide a high level of service to its customers. PECO's base rate caps will generally preclude incremental rate recovery on any of these incremental investments prior to January 1, 2011 (see the section titled "PECO must manage its costs due to the rate caps imposed on PECO" above).

Capital Markets / Financing Environment

        In order to expand PECO's operations and to meet the needs of its current and future customers, PECO invests in its business. PECO's ability to finance its business and other necessary expenditures is affected by the capital intensive nature of its operations and PECO's current and future credit ratings. The capital markets also affect Exelon's benefit plan assets. Further discussions of PECO's liquidity position can be found in the Liquidity and Capital Resources section above.

PECO's ability to grow its business is affected by the ability to finance capital projects.

        PECO's business requires considerable capital resources. When necessary, PECO secures funds from external sources by issuing commercial paper and, as required, long-term debt securities. PECO actively manages its exposure to changes in interest rates through interest-rate swap transactions and its balance of fixed- and floating-rate instruments. PECO currently anticipates primarily using internally generated cash flows and short-term financing through commercial paper to fund its operations as well as long-term external financing sources to fund capital requirements as the need arises. The ability to arrange debt financing, to refinance current maturities and early retirements of debt, and the costs of issuing new debt are dependent on:

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PECO's credit ratings influence its ability to raise capital.

        PECO has investment grade ratings and has been successful in raising capital, which has been used to further its business initiatives. Failure to maintain investment grade ratings would require PECO to incur higher financing costs.

Equity market performance affects Exelon's benefit plan asset values.

        The sharp decline in the equity markets since the third quarter of 2000 has reduced the value of the assets held in trusts to satisfy the obligations of pension and postretirement benefit plans. If the markets continue to decline, PECO may have higher funding requirements and pension and other postretirement benefit expense. Exelon will continue to manage the assets in the pension and postretirement benefit plans in order to achieve the best return possible in conjunction with its overall risk management practices and diversified approach to investment. Please refer to the Critical Accounting Estimates section that more fully describes the quantitative financial statement effects of changes in the equity markets on the benefit plan assets.

PECO's results of operations can be affected by inflation.

        Inflation affects PECO through increased operating costs and increased capital costs for transmission and distribution plant. As a result of the rate caps imposed under the legislation in Pennsylvania, PECO is not able to pass the costs of inflation through to customers.

Other

PECO may incur substantial cost to fulfill its obligations related to environmental matters.

        PECO's business is subject to extensive environmental regulation by local, state and Federal authorities. These laws and regulations affect the manner in which PECO conducts its operations and makes its capital expenditures. PECO is subject to liability under these laws for the costs of remediating environmental contamination of property now or formerly owned by PECO and of property contaminated by hazardous substances PECO generated. Management believes that it has a responsible environmental management and compliance program; however, PECO has incurred and expects to incur significant costs related to environmental compliance and site remediation and clean-up. Remediation activities associated with manufactured gas plant operations will be one source of such costs. Also, 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, 2002, PECO's reserve for environmental investigation and remediation costs was $40 million, exclusive of decommissioning liabilities. PECO has accrued and will continue to accrue amounts that management believes are prudent to cover these environmental liabilities, but PECO cannot predict with any certainty whether these amounts will be sufficient to cover PECO's environmental liabilities. Management cannot predict whether PECO will incur other significant liabilities for any additional investigation and remediation costs at additional sites not currently identified by PECO, environmental agencies or others, or whether such costs will be recoverable from third parties.

PECO's financial performance is affected by its ability to manage costs for security and liability insurance.

        Security.    In connection with the events of September 11, 2001, the electric and gas industries have developed additional security guidelines. The electric industry, through the North American Electric Reliability Council (NERC), developed physical security guidelines, which were accepted by the U.S. Department of Energy. In 2003, FERC issued minimum standards to safeguard the electric grid system

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control. These standards will be effective in 2004 and fully implemented by January 2005. The gas industry, through the American Gas Association, developed physical security guidelines that were accepted by the U.S. Department of Transportation. Exelon participated in the development of these guidelines and PECO is using them as a model for its security program.

        Insurance.    PECO, through Exelon, 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. Exelon is self-insured to the extent that any losses may exceed the amount of insurance maintained.

The possibility of attack or war may adversely affect PECO's results of operations, future growth and ability to raise capital.

        Any military strikes or sustained military campaign may affect PECO's operations in unpredictable ways, such as increased security measures. Just the possibility that infrastructure facilities, such as electric transmission and distribution facilities, would be direct targets of, or indirect casualties of, an act of terror or war may affect PECO's operations. War and the possibility of war may have an adverse effect on the economy in general. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect PECO's revenues or restrict PECO's future growth. Instability in the financial markets as a result of war may affect PECO's ability to raise capital.

The introduction of new technologies could increase competition within PECO's markets.

        While demand for electricity is generally increasing throughout the United States, the rate of construction and development of new, more efficient, electric generation facilities and distribution methodologies may exceed increases in demand in some regional electric markets. The introduction of new technologies could increase competition, which could lower prices and have an adverse affect on PECO's results of operations or financial condition.

New Accounting Pronouncements

        See ComEd, PECO and Generation—New Accounting Pronouncements above for a discussion of new accounting pronouncements.

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Generation

General

        On October 20, 2000, Exelon became the parent corporation for PECO and ComEd as a result of the completion of the transactions related to the Merger. Generation has included the ComEd's generation-related results of operations in its consolidated financial statements beginning October 20, 2000. The estimated impact of the Merger set forth herein reflects the effects ComEd's generation related results of operations prior to October 20, 2000.

Results of Operations

Year Ended December 31, 2002 Compared To Year Ended December 31, 2001

Significant Operating Trends—Generation

 
   2002
   2001
   Variance
   % Change
  
OPERATING REVENUES   $ 6,858   $ 6,826   $ 32   0.5 %
OPERATING EXPENSES                        
  Purchased Power     3,294     3,106     188   6.1 %
  Fuel     959     889     70   7.9 %
  Operating and Maintenance     1,656     1,528     128   8.4 %
  Depreciation     276     282     (6 ) (2.1 )%
  Taxes Other Than Income     164     149     15   10.1 %
   
 
 
 
 
    Total Operating Expense     6,349     5,954     395   6.6 %
   
 
 
 
 
OPERATING INCOME     509     872     (363 ) (41.6 )%
   
 
 
 
 
OTHER INCOME AND DEDUCTIONS                        
  Interest Expense     (75 )   (115 )   40   34.8 %
  Equity in Earnings (Losses) of Unconsolidated Affiliates, net     87     90     (3 ) (3.3 )%
  Other, Net     83     (8 )   91   n.m.  
   
 
 
 
 
    Total Other Income and Deductions     95     (33 )   128   n.m.  
   
 
 
 
 
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES     604     839     (235 ) (28.0 )%
INCOME TAXES     217     327     (110 ) (33.6 )%
   
 
 
 
 
INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES     387     512     (125 ) (24.4 )%
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES, (net of income taxes)     13     12     1   8.3 %
   
 
 
 
 
NET INCOME   $ 400   $ 524   $ (124 ) (23.7 )%
   
 
 
 
 

Net Income

        Generation's net income decreased by $124 million, or 24% in 2002. Net income was adversely impacted by a lower margin on wholesale energy sales due to depressed market prices for energy, a reduced supply of low-cost nuclear generation, and increased operating and maintenance expense. The decrease was partially offset by increased revenue from the acquisition of two generating plants in April 2002, increased investment income, decreased depreciation expense and decreased interest expense.

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Operating Revenues

        Operating revenues increased $32 million, or 1% in 2002. Sales to affiliates increased by $124 million. This increase was attributable to weather-related increased deliveries to PECO and ComEd. Revenue from marketing and trading decreased by $143 million, which was due to lower market prices on sales and losses sustained from proprietary trading activity. Market sales were negatively impacted by lower average market sales prices of $6.25/MWh. Excluding the benefit of $99 million of margin associated with the Texas plants acquisition, average market prices realized for the year ended December 31, 2002 were $7.44/MWh lower than the same 2001 period. The effect of the lower sales prices were partially offset by increased market sales volumes. Trading margin decreased $36 million, reflecting a $29 million loss for the year ended December 31, 2002 as compared to a $7 million gain in the same 2001 period.

Purchased Power

        Purchased power expense increased $188 million, or 6% in 2002. This increase in purchased power expense was primarily attributable to a 15.8% increase in purchased power volume. This was partially offset by average purchased power cost decreasing by $4.11/MWh for the year ended December 31, 2002 as compared to the same 2001 period. This decrease in average purchased power cost was principally attributed to lower realized wholesale market prices realized and reduced transmission costs.

Fuel

        Fuel expense increased $70 million in 2002. The increase was principally attributed to increased fossil fuel purchases related to new plant acquisitions in Texas and New England, as well as increased peaking production due to summer demand.

Operating Statistics

        For the year ended December 31, 2002 and 2001, Generation's sales and the supply of these sales, excluding the trading portfolio, were as follows:

Sales (in GWhs)
   2002
   2001
   % Change
  
Energy Delivery   118,473   116,917   1.3 %
Exelon Energy   5,502   6,876   (20.0 )%
Market Sales   83,565   72,333   15.5 %
   
 
 
 
Total Sales   207,540   196,126   5.8 %
   
 
 
 

Supply of Sales (in GWhs)
 
2002
 
2001
 
% Change
 
Nuclear Generation (1)   115,854   116,839   (0.8 )%
Purchases—non-trading portfolio (2)   78,710   67,942   15.8 %
Fossil and Hydro Generation   12,976   11,345   14.4 %
   
 
 
 
Total Supply   207,540   196,126   5.8 %
   
 
 
 
(1)
Excluding AmerGen.

(2)
Including PPAs with AmerGen.

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        Trading volume of 69,933 GWhs and 5,754 GWhs for the year ended December 31, 2002 and 2001, respectively, is not included in the table above. Generation's average revenue, supply cost, and margin on energy sales for the years ended December 31, 2002 and 2001 were as follows:

($/MWh)
   2002
   2001
   % Change
  
Average Revenue                  
  Energy Delivery   $ 33.48   $ 32.55   2.9 %
  Exelon Energy     44.87     41.53   8.0 %
  Market Sales     30.75     37.00   (16.9 )%
  Total—excluding the trading portfolio     32.68     34.51   (5.3 )%
Average Supply Cost (1)—excluding trading portfolio   $ 20.14   $ 20.26   (0.6 )%
Average Margin—excluding the trading portfolio   $ 12.54   $ 14.25   (12.0 )%
(1)
Average supply cost includes purchased power and fuel costs.

 
   2002
   2001
  
Nuclear fleet capacity factor (1)     92.7 %   94.4 %
Nuclear fleet production cost per MWh   $ 13.00   $ 12.78  
Average purchased power cost for wholesale operations per MWh   $ 41.83   $ 45.94  
(1)
Including AmerGen and excluding Salem.

Operating and Maintenance

        O&M expense increased $128 million, or 9%, for the year ended December 31, 2002 compared to the same period in 2001. The increase was due to the additional O&M expense of $80 million arising from an increased number of nuclear plant refueling outages during 2002 compared to 2001. Also, O&M expense increased $21 million due to plants acquired in 2002, as well as additional allocated corporate costs, including executive severance. These additional expenses were partially offset by other operating cost reductions, including $8 million related to fewer employees, a $10 million reduction in Generation's severance accrual and other cost reductions from Exelon's Cost Management Initiative. The severance reduction represents a reversal of costs previously charged to operating expense.

Depreciation

        Depreciation expense decreased $6 million, or 2%, for the year ended December 31, 2002 compared to 2001. This decrease is due to a $42 million reduction in depreciation expense arising from the extension of the useful lives on certain generation facilities in 2001, partially offset by $32 million of additional depreciation expense on capital additions placed in service, including the Southeast Chicago Energy Project in July 2002, and two generating plants acquired in April 2002.

Taxes Other Than Income

        Taxes other than income increased $15 million, or 10%, for the year ended December 31, 2002 compared to the same period in 2001 due primarily to an $8 million increase in property taxes.

Interest Expense

        Interest expense decreased $40 million, or 35%, for the year ended December 31, 2002, compared to the same period in 2001. The decrease is due to $19 million of lower interest related to a lower interest rate on the spent nuclear fuel obligation, and $33 million of lower affiliate interest expense. This decrease was partially offset by a $21 million increase in interest expense due to newly acquired long-term debt.

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Equity in Earnings of Unconsolidated Affiliates, net

        Equity in earnings of unconsolidated affiliates decreased $3 million, or 3%, in 2002 compared to 2001. This decrease was due to a $5 million decrease in Generation's equity earnings in AmerGen, primarily due to an increase in pension, medical, and incentive cost, partially offset by an increase in revenue. This decrease was partially offset by an increase of $2 million in Generation's equity earnings in Sithe.

Other, Net

        Other, Net increased $91 million in 2002, compared to 2001. The increase was primarily due to a $103 million increase in decommissioning trust fund investment income, partially offset by a $6 million decrease in affiliate interest income, and a $6 million decrease due to losses on the disposal and retirement of Generation assets.

Income Taxes

        The effective income tax rate was 35.9% for 2002 compared to 39.0% for 2001. This decrease was primarily attributable to tax-exempt interest deductions in 2002 and other tax benefits recorded in 2002.

Cumulative Effect of Changes in Accounting Principles

        On January 1, 2002, Generation adopted SFAS No. 141 resulting in a benefit of $13 million (net of income taxes of $9 million).

        On January 1, 2001, Generation adopted SFAS No. 133, as amended, resulting in a benefit of $12 million (net of income taxes of $7 million).

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

        The October 20, 2000 merger of PECO and Unicom, and the January 1, 2001 corporate restructuring, significantly impacted Generation's results of operations. To provide a more meaningful analysis of results of operations, the financial analysis below identifies the portion of the components of net income variance that is attributable to the former ComEd generation business unit results of operations and the portion of the variance that results from normal operations attributable to changes in Generation's underlying operations. The merger variance represents the former ComEd generation business unit results for the year ended December 31, 2000 prior to the October 20, 2000 acquisition date as well as the effect of merger-related costs incurred in 2000. The 2000 effects of the merger and

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restructuring were developed using estimates of various items, including allocation of corporate overheads and intercompany transactions.

 
    
    
    
   Components of Variance
  
Generation
   2001
   2000
   Variance
   Merger
Variance
   Normal
Operations
  
OPERATING REVENUES   $ 6,826   $ 3,274   $ 3,552   $ 2,772   $ 780  
OPERATING EXPENSES                                
  Purchased Power and Fuel     3,995     1,846     2,149     1,690     459  
  Operating & Maintenance     1,528     800     728     868     (140 )
  Depreciation     282     123     159     83     76  
  Taxes Other Than Income     149     64     85     108     (23 )
   
 
 
 
 
 
    Total Operating Expenses     5,954     2,833     3,121     2,749     372  
OPERATING INCOME     872     441     431     23     408  
   
 
 
 
 
 
OTHER INCOME AND DEDUCTIONS                                
  Interest expense     (115 )   (41 )   (74 )   (33 )   (41 )
  Equity in Earnings of Unconsolidated Affiliates, net     90     4     86     —     86  
  Other, Net     (8 )   16     (24 )   —     (24 )
   
 
 
 
 
 
    Total Other Income and Deductions     (33 )   (21 )   (12 )   (33 )   21  
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECTS OF CHANGES IN ACCOUNTING PRINCIPLES     839     420     419     (10 )   429  
INCOME TAXES     327     160     167     (9 )   176  
   
 
 
 
 
 
INCOME BEFORE CUMULATIVE EFFECTS OF CHANGES IN ACCOUNTING PRINCIPLES     512     260     252     (1 )   253  
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (net of income taxes)     12     —     12     —     12  
   
 
 
 
 
 
NET INCOME   $ 524   $ 260   $ 264   $ (1 ) $ 265  
   
 
 
 
 
 

Net Income

        Generation's net income increased $265 million for 2001, compared to 2000 excluding the effects of the Merger. This increase was primarily attributable to higher margins on increased market and affiliate wholesale energy sales, coupled with reduced operating expenses at the nuclear plants, partially offset by additional depreciation and decommissioning expense.

Operating Revenues

        Operating revenues increased $780 million for 2001, compared to 2000 excluding the effects of the Merger. Operating revenue increased due to higher market prices for energy. The increase in wholesale market prices, particularly in the PJM and MAIN regions, was conversely affected by higher fossil fuel prices. In addition, 2001 energy marketing activity resulted in mark-to-market gains of $16 million on non-trading contracts, and $14 million on trading contracts. This was partially offset by $6 million in realized trading losses.

Purchased Power and Fuel

        Purchased power and fuel costs increased $459 million for 2001, compared to 2000, excluding the effects of the Merger. This increase was due to increased fuel prices in the first quarter of 2001

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compared to the same period in the prior year. Also, Generation experienced an increase in volume sold during the peak demand season in 2001 compared to 2000.

Operating and Maintenance

        O&M expenses decreased $140 million for 2001, compared to 2000, excluding the effects of the Merger. O&M expenses were favorably affected by reductions in labor costs due to a decline in the number of employees and fewer nuclear outages in 2001 than in 2000, which offset the effect of increases in litigation-related expenses of $30 million.

Depreciation

        Depreciation expense increased $76 million for 2001, compared to 2000, excluding the effects of the Merger. The increase in depreciation expense was primarily due to an increase in decommissioning expense of $140 million resulting from the discontinuance of regulatory accounting practices associated with decommissioning costs for the former ComEd operating nuclear generating stations, partially offset by a $90 million reduction in depreciation and decommissioning expense attributable to the extension of estimated service lives of generating plants.

Taxes Other Than Income

        Taxes other than income taxes decreased $23 million for 2001, compared to 2000. Taxes other than income taxes decreased as a result of a reduction in payroll taxes due to a decline in the number of employees and a reduction in property taxes due to property value reassessments.

Interest Expense

        Interest expense increased $41 million for 2001, compared to 2000, excluding the effects of the Merger. This increase was primarily attributable to increased interest charges of $23 million on the note payable to Exelon, interest charges of $26 million due to the issuance of $700 million of 6.95% senior unsecured notes in a 144A offering in June 2001, $23 million of additional interest due to a full year of interest charges on the spent fuel obligation compared to only two months in 2000 for the former ComEd generating stations, and $15 million of interest charges from affiliates. These increases were partially offset by capitalized interest of approximately $17 million.

Equity in Earnings of Unconsolidated Affiliates, net

        Equity in earnings of unconsolidated affiliates increased $86 million for 2001, compared to 2000. Equity in earnings of unconsolidated affiliates increased primarily due to additional earnings of AmerGen and Sithe of $86 million in 2001 reflecting a full year of operations for Sithe and AmerGen's Oyster Creek plant in 2001.

Other, Net

        Other, Net decreased $24 million for 2001, compared to 2000. Investment income decreased by $29 million due to net realized losses of $127 million partially offset by interest and dividend income of $67 million on the nuclear decommissioning trust funds reflecting the discontinuance of regulatory accounting practices associated with nuclear decommissioning costs for the nuclear stations formerly owned by ComEd. The decrease in investment income was also offset by increased income of $31 million due to money market interest and interest on the loan to Sithe recorded in 2001.

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Income Taxes

        The effective income tax rate was 39.0% for 2001 as compared to 38.1% for 2000. The increase in the effective income tax rate was primarily attributable to a higher effective state income tax rate due to operations in Illinois subsequent to the merger and a reduction in investment tax credit amortization.

Cumulative Effect of Changes in Accounting Principles

        On January 1, 2001, Generation adopted SFAS No. 133, resulting in a benefit of $12 million (net of income taxes of $7 million).

Liquidity and Capital Resources

        Generation's business is capital intensive and requires considerable capital resources. Generation's capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financings including the issuance of commercial paper and borrowings or capital contributions from Exelon. Generation's access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. Capital resources are used primarily to fund Generation's capital requirements, including construction, investments in new and existing ventures, repayments of maturing debt and the payment of dividends. Any future acquisitions could require external financing or borrowings or capital contributions from Exelon.

Cash Flows from Operating Activities

        Cash flows provided by operations were $1,138 million in 2002, compared to $1,274 million in 2001. The decrease in cash flows from operating activities is primarily due to a $124 million decrease in net income, and a $197 million decrease in cash flow related to working capital. This decrease is partially offset by a $185 million increase in cash flows related to other operating activities not included in working capital. Generation's cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including Generation's affiliated companies, as well as settlements arising from Generation's trading activities. Generation's future cash flow from operating activities will depend upon future demand and market prices for energy and the ability to continue to produce and supply power at competitive costs.

        Generation participates in Exelon's defined benefit pension plans. Exelon's plans currently meet the minimum funding requirements of the Employment Retirement Income Security Act of 1974; however, Exelon made a discretionary plan contribution in 2002 of $150 million, of which $60 million was funded by Generation. Exelon also expects to make a discretionary plan contribution in 2003 of $300 million to $350 million.

Cash Flows from Investing Activities

        Cash flows used in investing activities were $1,674 million in 2002, compared to $1,043 million in 2001. Capital expenditures, including investment in nuclear fuel, were $990 million in 2002. In addition to the 2002 capital expenditures, Generation purchased two natural-gas and oil-fired generating plants from TXU on April 25, 2002. The $443 million purchase was funded with commercial paper, which Exelon issued and Generation is repaying from cash flows from operations. The balance of Generation's short-term borrowings at December 31, 2002 attributable to the plants purchased from TXU, was approximately $70 million. Investing activities also included a $2 million use of cash for the November 1, 2002 purchase of the Sithe New England assets. The $2 million use is net of $12 million of cash acquired. The remainder of the purchase was financed with a $534 million note issued to Sithe.

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        In February 2002, Generation entered into an agreement to loan AmerGen up to $75 million at an interest rate of one-month LIBOR plus 2.25%. In July 2002, the loan agreement and the loan were increased to $100 million and the maturity date was extended to July 1, 2003. As of December 31, 2002, the balance of the loan to AmerGen was $35 million. Generation has agreed to make capital contributions to AmerGen of 50% of the purchase price of any acquisitions that AmerGen makes. Generation's capital expenditures are expected to be funded by internally generated funds, Generation's borrowings or capital contributions from Exelon.

Cash Flows from Financing Activities

        Cash flows provided by financing activities were $370 million in 2002, compared to cash used of $11 million in 2001. During 2002, Generation obtained a $348 million loan from Exelon, which included $331 million for the acquisition of two generating plants. The prior year amount represented net distributions of $136 million to Exelon and the issuance of long-term debt of $821 million. Also, in 2001, Generation repaid $696 million it had borrowed from Exelon related to the acquisition of a 49.9% interest in Sithe.

        Financing activities in 2002 exclude the non-cash issuance of a $534 million note issued to Sithe for the November 1, 2002 acquisition of the Sithe New England assets and approximately $1.0 billion of Sithe New England long-term debt, which is reflected in Generation's Consolidated Balance Sheets as of December 31, 2002.

Credit Issues

        Generation meets its short-term liquidity requirements primarily through intercompany borrowings from Exelon and the issuance of commercial paper. Generation, along with Exelon, ComEd and PECO, participates in a $1.5 billion unsecured 364-day revolving credit facility with a group of banks. The credit facility became effective on November 22, 2002 and includes a term-out option that allows any outstanding borrowings at the end of the revolving credit period to be repaid on November 21, 2004. Exelon may increase or decrease the sublimits of each of the participants upon written notification to these banks. As of December 31, 2002, there was no sublimit for Generation. The credit facility is expected to be used by Generation principally to support its commercial paper program.

        Certain of the credit agreements to which Generation is a party require it to maintain a cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratio excludes certain changes in working capital and interest on Sithe New England's debt. Generation's threshold for the ratio reflected in the credit agreement cannot be less than 3.25 to 1 for the twelve-month period ended December 31, 2002. At December 31, 2002, Generation was in compliance with the credit agreement thresholds.

        At December 31, 2002, Generation's capital structure consisted of 49% common stock, 15% notes payable and 36% long-term debt.

        To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. Participation in the money pool is subject to authorization by the Exelon corporate treasurer. ComEd and its subsidiary Commonwealth Edison of Indiana, Inc., PECO, Generation and Business Services Company may participate in the money pool as lenders and borrowers, and Exelon as a lender. Funding of, and borrowings from, the money pool are predicated on whether such funding results in mutual economic benefits to each of the participants, although Exelon is not permitted to be a net borrower from the money pool. Interest on borrowings is based on short-term market rates of interest, or specific borrowing rates if the funds are provided by external financing. There have been no material money