Exelon Generation 10K 2002 Annual report

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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 — 37^th 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 — 37^th 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	Yesý	Noo
Commonwealth Edison Company	Yeso	Noý
PECO Energy Company	Yeso	Noý
Exelon Generation Company, LLC	Yeso	Noý

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 athttp://www.sec.gov and Exelon Corporation's website atwww.exeloncorp.com.

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):

•: Energy Delivery, whose businesses include the regulated sale of electricity and distribution and transmission services by ComEd in northern Illinois and PECO in southeastern Pennsylvania and the sale of natural gas and distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia.
•: Generation, consisting of the owned and contracted for electric generating facilities, energy marketing operations, and equity interests in Sithe Energies, Inc. (Sithe) and AmerGen Energy Company, LLC (AmerGen).
•: Enterprises, consisting of competitive retail energy sales, energy and infrastructure services, communications and other investments (weighted towards the communications, energy services and retail services industries).

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

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.

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).

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.

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.

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

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:

•: ComEd's pending residential delivery services rate proceeding

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

•: Illinois electricity market development

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

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

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

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

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

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

•: Funding of certain programs for customer and governmental groups

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

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

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

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

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

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

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

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.

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

	Allowed Recovery, Excluding Gross Receipts Tax
Year	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

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,

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.

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).

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.

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

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

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

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.

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.

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.

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

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

Fossil and Hydroelectric Facilities.

Fossil units include:

•: base-load units—the coal-fired units at Eddystone and Cromby and Generation's interests in the Conemaugh Stations and Keystone;
•: intermediate units—the Cromby, Eddystone, and Mystic units that have dual fuel (oil/gas) capability; Handley, Mountain Creek and New Boston are gas fueled stations, Wyman is an oil fueled station; and
•: peaking units—oil- or gas-fired steam turbines, combustion turbines and internal combustion units at various locations.

Hydroelectric facilities include:

•: base-load units—at the Conowingo run-of-river hydroelectric facility on the Susquehanna River in Harford County, Maryland; and
•: intermediate units—at the Muddy Run pumped-storage hydroelectric facility in Lancaster County, Pennsylvania.

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

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

•: a new eight unit 350-MW gas facility was brought on-line in July 2002 in the Mid-West region,
•: control system upgrades at the Conowingo and Muddy Run hydro facilities to improve plant efficiency, and
•: completion of a major turbine overhaul at the Cromby coal unit and further turbine overhauls are being studied for economic feasibility.

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

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

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

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

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.

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.

(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

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

(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.

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.

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

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

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.

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

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

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

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

Air

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

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

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

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

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

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

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

Costs

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

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

Other Subsidiaries of ComEd and PECO with Publicly Held Securities

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

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.

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.

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

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.

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.

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)

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.

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.

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.

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.

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.

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.

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,
	For the Years Ended December 31,				Oct. 20- Dec. 31 2000			Jan. 1- Oct. 19 2000		For the Years Ended December 31,
	2002		2001		Oct. 20- Dec. 31 2000			Jan. 1- Oct. 19 2000		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

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

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

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:

•: use financial derivatives to manage our exposure to interest rate fluctuations related to our variable rate debt instruments, changes in interest rates related to planned future debt issuances prior to their actual issuance and changes in the fair value of outstanding debt which we are planning to retire early,
•: enter into derivatives to manage the physical and financial risks associated with our energy supply and load obligations, and
•: enter into energy related derivatives for trading or speculative purposes.

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.

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

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.

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:

•: Competitive Transition Charges: These charges represent PECO's stranded costs that the PUC determined would be allowed to be recoverable through regulated rates. These costs are related to the deregulation of the generation portion of the electric utility business in Pennsylvania. The unamortized balance of the CTC of $4.6 billion and $4.9 billion as of December 31, 2002 and 2001, respectively, was recorded on our Consolidated Balance Sheets. The CTC includes Intangible Transition Property sold to PECO Energy Transition Trust, a wholly-owned subsidiary of PECO, in connection with the securitization of PECO's stranded cost recovery. CTC is being amortized through December 31, 2010 with a rate of return on the unamortized balance of 10.75%. See ITEM 1. Business—General—Energy Delivery—Retail Electric Services—PECO for additional discussion of CTC amortization.
•: Recoverable Transition Costs: These charges, related to the recovery of ComEd's former generating plants, are amortized based on the expected return on equity of ComEd in any given year. At December 31, 2002 and 2001, ComEd had $175 million and $277 million, respectively, in recoverable transition costs recorded in our Consolidated Balance Sheets. ComEd expects to fully recover and amortize these charges by the end of 2006, but may increase or decrease its annual amortization to maintain its earnings within the earnings cap provisions established by Illinois legislation. See ITEM 8. Financial Statements and Supplementary Data—ComEd—Note 5 of Notes to Consolidated Financial Statements for discussion of recoverable transition cost amortization.
•: Recoverable Deferred Income Taxes: These costs represent the difference between the method in which the regulator allows for the recovery of income taxes and how income taxes would be

recorded by unregulated entities. These recoverable deferred income taxes, recorded in compliance with SFAS No. 109, "Accounting for Income Taxes," include the deferred tax effects associated principally with liberalized depreciation for PECO and excess deferred taxes and ITC amortization for ComEd. These amounts are accounted for in accordance with the ratemaking policies of the ICC and PUC, as well as the revenue impacts thereon, and assume continued recovery of these costs in future rates. At December 31, 2002 and 2001, ComEd had $(68) million and $26 million, respectively, in recoverable deferred income taxes recorded in ComEd's Consolidated Balance Sheets. At December 31, 2002 and 2001, PECO had $729 million and $675 million, respectively, in recoverable deferred income taxes recorded in PECO's Consolidated Balance Sheets.

•: Nuclear Decommissioning Costs for Retired Plants: These costs represent the amount of future nuclear decommissioning costs related to the retired former ComEd plants which are being recovered through rates. At December 31, 2002 and 2001, ComEd had $248 million and $310 million, respectively, in nuclear decommissioning costs for retired plants recorded in ComEd's Consolidated Balance Sheets. These costs will be recovered in rates and amortized on a straight-line basis to earnings by the end of 2006.
•: Reacquired Debt Costs and Interest Rate Swap Settlements: These costs relate to amounts paid to reacquire debt early and to settle interest rate hedges to mitigate interest rate risks and capitalize on lower interest rate debt. These amounts are deferred and amortized over the rate-recovery period, which is over the life of the new debt issued to finance the debt redemption. At December 31, 2002 and 2001, ComEd had $84 million and $54 million, respectively, in reacquired debt costs and interest rate swap settlements recorded in ComEd's Consolidated Balance Sheets. At December 31, 2002 and 2001, PECO had $53 million and $58 million, respectively, in reacquired debt costs recorded in PECO's Consolidated Balance Sheets.

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

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

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:

•

decommissioning cost studies prepared by a third party

•: these decommissioning studies represent a marketplace assessment of costs and the timing of retirement activities validated by comparison to current decommissioning projects and other third party estimates

•

annual cost escalation studies to determine escalation factors based on inflation indices used in decommissioning cost studies for the following major categories:

•: labor,
•: equipment and materials,
•: energy,
•: other (taxes, insurance, fees, etc.), and
•: low-level radioactive waste disposal costs.

•

use of probabilistic cash flow models to measure the fair value including:

•: the probability of various cost levels, and
•: the probability of various timing scenarios incorporating the factors of current license lives and life extension and the timing of DOE acceptance for disposal of our spent nuclear fuel.

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:

•: an impairment loss be recognized if the carrying amount of an asset is not recoverable from its undiscounted cash flows, and
•: the impairment loss be measured as the difference between the carrying amount and the fair value of the asset.

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 timing of future rate case filings to establish new rates for bundled service after the then scheduled 2004 expiration of the rate freeze period, which has subsequently been extended to 2006 by Illinois law. Rate changes were assumed to occur at various points in 2005 through 2007 in the different scenarios.
•: The cash flow impact of the expiration of the rate freeze and the resolution of uncertainties regarding future commodity risk at the expiration of the current PPA with Generation, the resolution of ComEd's POLR obligation and various other risks and uncertainties.

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

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.

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,

$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

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

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

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.

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.

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.

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.

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.

•: 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	)%

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.

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.

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.

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,

approximately 18,700 retail customers, representing 22% of total annual retail deliveries, had elected to purchase energy from the PPO or an ARES, compared to approximately 9,500 customers, representing 17% of total annual retail deliveries, as of December 31, 2000.

•: 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

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.

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

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

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
				Payment due within							Due after 5 Years
	Total			1 Year			2-3 Years		4-5 Years		Due after 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."

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

•: long-term debt see Note 10
•: notes payable see Note 9
•: operating leases see Note 16
•: Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding the Company's Subordinated Debt Securities see Note 13
•: Midwest Agreement see Note 19

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
			Expiration within						After 5 Years
	Total		1 Year		2-3 Years		4-5 Years		After 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;

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:

•: ComEd's pending residential delivery services rate proceeding

proposed in the pending proceeding by a consulting firm engaged by the ICC to audit ComEd's test year expenditures, would not be reflected in the revenue requirement. Under the Agreement, distribution system plant reflected in the rate filing would be considered prudent and used and useful for purposes of this and future rate proceedings.

•: Illinois electricity market development

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

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

•: Funding of certain programs for customer and governmental groups

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

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

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

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

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:

•: credit availability from banks and other financial institutions,

•: maintenance of acceptable credit ratings (see credit ratings in the credit issues section of Liquidity and Capital Resources above),
•: investor confidence in ComEd and Exelon,
•: general economic and capital market conditions,
•: the success of current projects, and
•: the perceived quality of new projects.

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

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.

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	%

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.

(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.

As of December 31, 2002, the customer load served by alternative suppliers was 1,002 MW or 12.8% as compared to 1,003 MW or 13.0% as of December 31, 2001. The percent of PECO's total retail deliveries for which PECO was electric supplier was 92.0% in 2002, compared to 79.8% in 2001. As of December 31, 2002, the number of customers served by alternative suppliers was 277,805 or 18.2% as compared to December 31, 2001 of 371,500 or 24.4%. The increases in customers and the percentage of load served by PECO primarily resulted from customers selecting or returning to PECO as their electric generation supplier.

•: 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.

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.

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.

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.

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.

(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.

As of December 31, 2001, the customer load served by alternative suppliers was 1,003 MWs or 13.0% as compared to the same prior year period of 2,631 MWs or 34.9%. For the year ended December 31, 2001, the percent of load sold by PECO increased by 17.2% to 79.8% of total retail deliveries as compared to 62.6% in 2000. This reduction in the customers and the percentage of load served by alternative suppliers, primarily resulted from small and large commercial and industrial customers selecting or returning to PECO as their electric generation supplier.

As of December 31, 2001, the number of customers served by alternative suppliers was 371,500 or 24.4% as compared to December 31, 2000 of 269,395 or 18.0%. The increase from the prior year is primarily a result of the CDS agreements for residential customers with the New Power and Green Mountain. As of December 31, 2001, there were 227,349 residential customers assigned to these generation providers as part of the agreement.

•

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

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.

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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.

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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.

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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.

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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
			Payment due within						Due after 5 Years
	Total		1 Year		2-3 Years		4-5 Years		Due after 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:

•: long-term debt see Note 11
•: notes payable see Note 10
•: COMRPS see Note 15
•: operating leases see Note 18

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
			Expiration within						After 5 Years
	Total		1 Year		2-3 Years		4-5 Years		After 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.

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(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.

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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:

•: credit availability from banks and other financial institutions,
•: maintenance of acceptable credit ratings (see credit ratings in the credit issues section of Liquidity and Capital Resources above),
•: investor confidence in PECO and Exelon,
•: general economic and capital market conditions and
•: the success of current projects.

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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 pool transactions in 2002.

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Generation's access to the capital markets and its financing costs in those markets are dependent on its securities ratings. None of Generation's borrowings is 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. From time to time Generation enters into energy commodity and other derivative transactions that require the maintenance of investment grade ratings. Failure to maintain investment grade ratings would allow the counterparty to terminate the derivative and settle the transaction on a net present value basis. The following table shows Generation's securities ratings at December 31, 2002:

		Securities		Moody's Investors Service		Standard & Poor's		Fitch Ratings
Generation		Senior unsecured debt		Baa1		A-		BBB+
		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, Generation can only pay dividends from undistributed or current earnings. Generation is precluded from lending or extending credit or indemnity to Exelon. At December 31, 2002, Generation had undistributed earnings of $924 million.

Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations

Generation's contractual obligations as of December 31, 2002 are as follows:

			Payment Due within
			Payment Due within						Due After 5 Years
	Total		1 Year		2-3 Years		4-5 Years		Due After 5 Years
	(in millions)
Long-Term Debt	$	2,137	$	5	$	1	$	1,036	$	1,095
Short-Term Note to Sithe		534		534		—		—		—
Note Payable to Exelon Corporation		329		329		—		—		—
Operating Leases		592		32		45		51		464
Purchased Power Obligations		14,729		2,677		2,987		1,856		7,209
Spent Nuclear Fuel Obligations		858		—		—		—		858

Total Contractual Obligations	$	19,179	$	3,577	$	3,033	$	2,943	$	9,626

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

•: Long-Term Debt see Note 10
•: Short-Term Note to Sithe see Note 4
•: Notes payable to Exelon for the acquisition of generating plants from TXU see note 16
•: Operating Leases see Note 13
•: Purchased Power Obligations see Note 13
•: Spent Nuclear Fuel Obligation see Note 9

Generation has a long-term supply agreement through December 2022 with Distrigas to guarantee physical gas supply to Mystic 8 and Mystic 9 generating units. Under the agreement, prices are indexed to New England gas markets.

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Generation has an obligation to decommission its nuclear power plants. Generation's current estimate of decommissioning costs for the nuclear plants owned by Generation is $7.4 billion in current year (2003) dollars. Nuclear decommissioning activity occurs primarily after a plant is retired. Based on the extended license lives of its nuclear plants, Generation will begin decommissioning its plants from 2014 through 2056, with expenditures primarily occurring when its operating plants are decommissioned, during the period from 2029 through 2056. At December 31, 2002, the decommissioning liability, which is recognized over the life of the plant, was recorded in Generation's Consolidated Balance Sheets as Accumulated Depreciation and Deferred Credits and Other Liabilities in the amounts of $2.8 billion and $1.4 billion, respectively. To fund future decommissioning costs, Generation held $3.1 billion of investments in trust funds, including net unrealized gains and losses, at December 31, 2002.

Generation'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 and financing arrangements to secure its obligations, are as follows:

			Expiration within
			Expiration within						2008 and beyond
	Total		2003		2004-2005		2006-2007		2008 and beyond
Credit Facility(a)	$	—	$	—	$	—	$	—	$	—
Letters of Credit (non-debt)(b)		11		6		5		—		—
Letters of Credit (Long-Term Debt)(c)		346		195		151		—		—
Performance Guarantees(d)		101		—		—		—		101
Surety Bonds(e)		43		—		—		—		43
Energy Marketing Contract Guarantees(f)		1		1		—		—		—
Nuclear Insurance Guarantee(g)		134		—		—		—		134
Sithe New England Equity Guarantee(h)		38		38		—		—		—

Total Commercial Commitments	$	674	$	240	$	156	$	—	$	278

(a): Credit Facility—Exelon, along with ComEd, PECO and Generation, maintain a $1.5 billion 364-day credit facility to support commercial paper issuances. At December 31, 2002, there were no borrowings against the credit facility. Generation does not have a sublimit under the facility. Additionally, at December 31, 2002, Generation did not have any commercial paper outstanding.
(b): Letters of Credit (non-debt)—Non-debt letters of credit maintained 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): Performance Guarantees—Guarantees issued to ensure execution under specific contracts.
(e): Surety Bonds—Guarantees issued related to contract and commercial surety bonds, excluding bid bonds.
(f): Energy Marketing Contract Guarantees—Guarantees issued to ensure performance under energy commodity contracts.
(g): Nuclear Insurance Guarantee—Guarantees of nuclear insurance required under the Price-Anderson Act. This amount relates to Generation's guarantee of AmerGen's plants. Exelon has a $1.2 billion guarantee relating to Generation's directly owned plants that is not included in this amount.

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(h): Sithe New England Equity Guarantee—See ITEM 8. Financial Statements and Supplementary Data—Generation Note 4 of the Notes to Consolidated Financial Statements for further information on the $38 million guarantee. After construction of the SBG facilities is complete, Generation could be required to guarantee up to an additional $42 million in order to ensure that the SBG facilities have adequate funds available for potential outage and other operating costs and requirements.

Sithe Boston Generation Project Debt. In November 2002, Generation purchased the assets of Sithe New England. Sithe Boston Generating, LLC (SBG), a project subsidiary of Sithe New England has a $1.25 billion credit facility (SBG Facility), most of which is available to finance the construction projects of SBG. The outstanding balance of this facility at December 31, 2002 was $1.0 billion. The SBG Facility provides that if these construction projects are not completed by June 12, 2003, the SBG Facility lenders will have the right, but will not be required, to, among other things, declare all amounts then outstanding under the SBG Facility and the interest rate swap agreements to be due. Generation believes that the construction projects will be substantially complete by June 12, 2003, but that all of the approvals required under the SBG Facility may not be issued by that date. Generation is currently evaluating whether the requirements of the SBG Facility relating to the construction projects can be satisfied by June 12, 2003. In the event that the requirements are not expected to be satisfied by June 12, 2003, Generation will contact the SBG Facility lenders concerning an amendment or waiver of these provisions of the SBG Facility. Generation currently expects that arrangements for such an amendment or waiver, if necessary, can be successfully negotiated with the SBG Facility lenders.

Unconsolidated Equity Investments. Generation is a 49.9% owner of Sithe and accounts for the investment as an unconsolidated equity investment. The Sithe New England asset purchase did not affect the accounting for Sithe as an equity investment. Separate from the Sithe New England transaction, Generation is subject to a PCA that gives Generation the right to Call the remaining 50.1% of Sithe, and gives the other Sithe shareholders the right to 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. At the end of this exercise period, which is December 2005, if Generation has not exercised its Call option and the other stockholders have not exercised their Put rights, Generation will have an additional one-time option to purchase shares from the other stockholders to bring Generation's ownership in Sithe from the current 49.9% to 50.1% of Sithe's total outstanding common stock.

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, the 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.

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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 new generating facilities, $461 million of subordinated debt, $103 million of line of credit borrowings, $43 million of 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.

Additionally, the debt on the books of Generation's unconsolidated equity investments and joint ventures is not reflected on Generation's Consolidated Balance Sheets. Generation estimates that this debt, including Sithe's debt described in the preceding paragraph, totals approximately $1.3 billion and that Generation's portion of that amount, based on its ownership interest in the investments, is approximately $673 million.

Generation's equity investment in AmerGen was $160 million and $95 million at December 31, 2002 and 2001, respectively. Generation and British Energy, Generation's joint venture partner in AmerGen, have each agreed to provide up to $100 million to AmerGen at any time that the Management Committee of AmerGen determines that, in order to protect the public health and safety and/or to comply with NRC requirements, these funds are necessary to meet ongoing operating expenses or to safely maintain any AmerGen plant. The current financial condition of British Energy has been the focus of media attention recently. Generation cannot predict the ability of British Energy to provide funds to AmerGen. However, Generation does not believe this will impact AmerGen's ability to conduct its business.

Other

Generation's cash flow hedges are impacted by commodity prices. These hedge contracts primarily represent forward sales of Generation's excess capacity that it expects to deliver. The majority of these contracts are for delivery within one year. These contracts have specified credit limits pursuant to standardized contract terms and require that cash collateral be posted when the limits are exceeded. When power prices increase relative to Generation's forward sales prices, it can be subject to collateral calls if Generation exceeds its credit limits. However, when power prices return to previous levels or when Generation delivers the power under its forward contracts, the collateral would be returned to Generation with no impact on its results of operations. Generation believes that it has sufficient capability to fund any collateral requirements that could be reasonably expected to occur

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The NRC regulates the sufficiency of Generation's nuclear decommissioning trust funds. Generation is required to provide to the NRC a biennial report by unit (annually for the retired units) addressing Generation's ability to meet the NRC estimated funding levels (NRC Funding Levels) with scheduled contributions and earnings of the decommissioning trust funds. As of December 31, 2002, Generation has a number of units, which, due to current market conditions, are being funded at a rate less than anticipated with respect to the NRC's Funding Levels. Generation's calculations indicate that over time Generation may need to adjust its funding levels by up to $190 million, or less than 5% of the total. Generation will submit its biennial report to the NRC at the end of March 2003. At that time, Generation will address potential actions, in accordance with NRC requirements, to assure that Generation will remain adequately funded compared to the NRC Funding Levels. Taking into account anticipated license extensions, long-term earnings of fund investments and other factors, Generation still believes that scheduled regulated collections from ComEd and PECO customers will provide adequate funding to decommission its nuclear facilities in accordance with regulatory requirements in spite of any temporary shortfall in NRC Funding Levels.

Critical Accounting Estimates

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

Business Outlook and the Challenges in Managing Our Business

Generation faces a number of challenges in achieving its vision and keeping its commitments to its customers and investors; however, there are two principal areas where Generation focuses its attention. First, Generation's financial performance is significantly affected by the availability and utilization of its generation facilities. As the largest U.S. nuclear generator, Generation faces operational and regulatory risks that, if not managed diligently, could have significant adverse consequences. Second, Generation's results of operations are directly affected by wholesale energy prices. Energy prices are driven by demand factors such as weather and economic conditions in Generation's service territories. They are also driven by supply factors in the regions where Generation operates currently have excess capacity. Over the last several years, wholesale prices of electricity have generally been low. The possibility of continued low wholesale prices, coupled with a continued economic recessionary trend, could adversely affect Generation's business. These and other challenges that will affect how Generation manages its business are described below.

Generation operates a fleet of generating assets and markets the output of a portfolio of supply, which includes 100% owned assets, co-owned facilities and purchased power. As discussed previously, Generation has entered into long-term PPAs with ComEd and PECO. The majority of Generation's portfolio is used to provide power under these agreements. To the extent the portfolio is not needed to supply power to ComEd or PECO, its output is sold on the wholesale market. Generation's ability to grow is dependent upon its ability to cost-effectively meet ComEd's and PECO's load requirements, to manage its power portfolio and to effectively handle the changes in the wholesale power markets.

Generation's financial performance may be affected by liabilities arising from its ownership and operation of nuclear facilities.

The ownership and operation of nuclear facilities involve certain risks, including: mechanical or structural problems; inadequacy or lapses in maintenance protocols; the impairment of reactor operation and safety systems due to human error; the costs of storage, handling and disposal of nuclear material; and uncertainties with respect to the technological and financial aspects of decommissioning

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nuclear facilities at the end of their useful lives. The following are among the more significant of these risks:

Operational risk. Operations at any nuclear generation plant could degrade to the point where Generation would have to shut down the plant. If this were to happen, the process of identifying and correcting the causes of the operational downgrade to return the plant to operation could require significant time and expense, resulting in both lost revenue and increased purchased power and fuel expense to meet its supply commitments. For plants operated by Generation but not wholly-owned by Generation, Generation could incur liabilities to the co-owners. Generation may choose to close a plant rather than incur substantial costs to restart the plant.

Nuclear accident risk. Although the safety record of nuclear reactors has been very good, accidents and other unforeseen problems have occurred both in the United States and elsewhere. The consequences of an accident can be severe and may include loss of life and property damage. Any resulting liability from a nuclear accident could exceed Generation's insurance coverages and significantly affect its results of operations or financial position. See ITEM 8. Financial Statements and Supplementary Data—Generation Note 13 of the Notes to Consolidated Financial Statements for further discussion of nuclear insurance.

Nuclear regulation. The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear facilities. Changes in regulations by the NRC that require a substantial increase in capital expenditures or that result in increased operating or decommissioning costs could adversely affect Generation's results of operations or financial condition. Events at nuclear plants owned by others, as well as those owned by Generation, may initiate such actions. Additional security requirements could also be imposed.

Plant life extensions. In 2001, Generation extended the estimated lives of certain nuclear stations. This change in estimate reflects the current and planned applications to the NRC to renew the operating licenses of Generation's nuclear stations. These applications for renewal, if approved by the NRC, will allow Generation to operate these plants for an additional 20 years longer than originally authorized. Nuclear station service life extensions are subject to NRC approval of an extension of existing NRC operating licenses, which are generally 20 years. Generation continues to fully believe that any such applications for renewal of operating licenses will be approved. However, if the NRC does not extend the operating licenses for Generation's nuclear stations, Generation's results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning payments.

Generation's financial performance is affected in large measure by the availability and use of its nuclear generation capacity.

Nuclear capacity factors. Generation capacity factors, particularly nuclear capacity factors, significantly affect its results of operations. Nuclear plant operations involve substantial fixed operating costs, but produce electricity at low marginal costs due to low variable fuel costs. Consequently, to be successful, Generation must consistently operate its nuclear generating facilities at high capacity factors. Generation's nuclear fleet performed at a 92.7% capacity factor (which represents the percentage of the total maximum energy that could be produced if facilities were operating full-time year round) in 2002 and is targeted to operate at a 94.2% capacity factor in 2003. In calculating capacity factors, Generation's nuclear fleet includes the AmerGen plants and excludes the Salem generation facility, which is operated by Public Service Enterprise Group Incorporated (PSE&G). Lower capacity factors would increase its operating costs and could require Generation to generate additional energy from its fossil or hydroelectric facilities or purchase additional energy in the spot or forward markets in order to satisfy its obligations to ComEd and PECO and other committed third-party sales. These sources

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generally are at a higher cost than Generation otherwise would have incurred to generate energy from its nuclear stations.

Refueling outage scheduling at nuclear plants affects availability and costs. Outages at nuclear stations to replenish fuel require the station to be "turned off." Refueling outages are planned to occur once every 18 to 24 months and currently average approximately 22 days in duration. Generation has significantly decreased the length of refueling outages in recent years. However, when refueling outages last longer than anticipated or Generation experiences unplanned outages, Generation faces lower margins due to higher energy replacement costs and/or lower energy sales. Each twenty-day outage, depending on the capacity of the station, will decrease the total nuclear annual capacity factor between 0.1% and 0.4%. The number of refueling outages, including AmerGen, will decrease to eight in 2003 from eleven in 2002. Maintenance and capital expenditures are expected to decrease by approximately $45 million and $10 million, respectively, in 2003 as compared to 2002 as a result of fewer nuclear refueling outages.

Nuclear fuel quality may affect costs. The quality of nuclear fuel utilized by Generation can affect the efficiency and costs of its operations. Certain Generation nuclear units have recently identified to have a limited number of fuel performance issues. While actions have been taken in accordance with Generation's policies and procedures to ensure there are no public, personnel or operational issues, evaluation continues and further actions are under consideration. These actions, such as down powers, mid-cycle outages, and/or accelerated replacement of suspect fuel assemblies, will result in increased costs in 2003. In March 2003, a decision was made to replace suspect fuel assemblies at the Quad Cities Unit 1 facility. The 2003 impact from this decision is estimated to be approximately $20 million, before income taxes. Generation continues to evaluate other units that utilize similar fuel assemblies, but there currently are no plans to replace this fuel on an accelerated basis.

Generation is directly affected by wholesale energy prices.

Generation sells energy in the wholesale markets after meeting its contractual commitments to Energy Delivery and other parties. These sales expose Generation to the risks of rising and falling prices in those markets, and cash flows may vary accordingly. The amount of generation capacity that is exposed to the volatility of market prices depends inversely on the level of demand at ComEd and PECO.

The wholesale prices of electricity have generally been lower than historical levels over the last few years. A continued trend of low wholesale electricity prices could negatively affect Generation's results of operations. Factors that affect wholesale energy prices include the overall demand for energy, fossil fuel costs and excess capacity within the industry.

Demand for energy. An increased demand for energy will normally cause energy prices to increase; however, if this increase in demand drives an incremental increase in supply, energy prices may be less affected. The demand for energy is directly affected by weather conditions and economic conditions in Generation's service territories.

Weather conditions. Generation's operations are affected by weather, which affects demand for electricity as well as operating conditions. Generation manages its business based upon normal weather assumptions. To the extent that weather is warmer in the summer or colder in the winter than assumed, Generation may require greater resources to meet its contractual requirements to ComEd and PECO. Extreme summer conditions or storms may affect the availability of generation capacity and transmission, limiting Generation's ability to send power to where it is sold. These conditions, which may not have been fully anticipated, may have an adverse affect by causing Generation to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when those markets are weak. Generation does incorporate contingencies into its planning for

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extreme weather conditions, including reserving capacity to meet summer loads at levels representative of warmer than normal weather conditions.

Economic conditions. Economic conditions and activity in ComEd's and PECO's service territories directly affect the demand for electricity and gas. Changes in economic conditions and activity in ComEd's and PECO's service territories and in other parts of the United States can affect the level of operations required in the generating facilities as well as the prevailing prices of electricity and gas in the wholesale markets in which Generation does business.

Fossil fuel costs. At any given time, the open market wholesale price of electricity is affected by the cost of supplying one more unit of electricity to the market at that time. Many times the next unit of electricity supplied would be supplied from generating stations fueled by fossil fuels, primarily natural gas. Consequently, the open market wholesale price of electricity may reflect the cost of gas plus the spark spread, the cost to convert gas to electricity. Therefore, changes in the cost of gas may impact the open market wholesale price of electricity.

Excess capacity. In addition to being affected by demand factors such as weather, the economy, and fossil fuel costs, energy prices are also impacted by the amount of supply available in a region. In the markets where Generation sells power, there has been a significant increase in the number of new power plants coming on-line which has driven down power prices over the last few years. An "excess supply" problem currently exists in many parts of the country. A key factor for Generation's future earnings is the timing of a return to more normal levels in the supply-demand balance within the regions where Generation operates.

The scope and scale of Generation's nuclear generation resources provide a cost advantage in meeting its contractual commitments and enable Generation to sell power in the wholesale markets.

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 energy wholesale markets. Generation's resources, including AmerGen, include interest in 11 nuclear generation stations, consisting of 19 units, which generated 125,916 GWhs, or more than half of Generation's total supply in 2002. 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 required. Generation's nuclear plants benefit from stable fuel costs, minimal environmental impact from operations, and a safe operating history.

Generation's financial performance will be affected by its ability to effectively operate and integrate the assets of Sithe New England into its business and to market the output.

In November 2002, Generation acquired the generating assets of Sithe New England, which includes 2,421 MWs of gas-fired combined facilities under construction and several operating generating facilities, which together with the assets under construction total 4,066 MWs of capacity. The facilities under construction (Mystic 8, Mystic 9, and Fore River) are currently in the final stages of construction and testing. Generation anticipates commercial operation dates during the second quarter of 2003. These projects have experienced delays in construction and any further delays could adversely affect Generation's results. See further discussion of the Sithe Boston Generation Project Debt in the Liquidity and Capital Resources section of ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Generation. With the continued low wholesale energy prices, Generation anticipates that the effects of its Sithe investment and the Sithe New England acquisition will be dilutive to earnings by approximately $125 million before income taxes in 2003.

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Power Team has not fully committed the output from these facilities into the New England markets. As such, the uncommitted capacity of the Sithe New England assets is subject to the fluctuations in market demand and market prices.

Substantially all of the natural gas requirements for Mystic 8 and Mystic 9 will be supplied through a twenty-year natural gas contract that became effective on December 1, 2002 with 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. In the interim, any disruption in LNG supplies to the Distrigas facilities could restrict the operating abilities of Mystic 8 and Mystic 9.

The interaction between ComEd and PECO's businesses and Generation's businesses provide a partial hedge.

The price of power purchased and sold in the open wholesale energy markets can vary significantly in response to market conditions. Both ComEd and PECO have entered into long-term agreements for the next several years with Generation to procure the power at fixed rates needed to meet the demand of their customers. The amounts provided to affiliates vary from month to month; however, delivery requirements are generally highest in the summer when wholesale power prices are also generally highest. Therefore, energy committed to serve ComEd and PECO customers is not exposed to the price uncertainty of the open wholesale energy market. Consequently, Generation has limited its earnings exposure to the volatility of the wholesale energy market to the energy generated beyond the ComEd and PECO requirements, as well as any other contracted longer term obligations. Generally, between 60% and 70% of Generation's electricity generated serves ComEd and PECO customers. Generation expects such levels to decrease to between 55% and 60% as a result of activating the acquired Sithe New England plants, which are currently under construction. One of the responsibilities of Power Team is to establish a hedging strategy, incorporating the load obligations of ComEd and PECO, to minimize the contracted volatility of Generation's earnings and cash flows, and to maximize the value of economic generation in excess of that needed to serve ComEd and PECO requirements.

Generation's financial performance depends on its ability to respond to competition in the energy industry.

As a result of industry restructuring, numerous generation companies created by the disaggregation of vertically integrated utilities have become active in the wholesale power generation business. In addition, independent power producers (IPP) have become prevalent in the wholesale power industry. In recent years, IPPs and the generation companies of disaggregated utilities have installed new generating capacity at a pace greater than the growth of electricity demand. As a result, the energy generation business is currently suffering from over capacity in certain parts of the country, which reduces wholesale energy prices. As discussed above, Generation is well positioned because it has entered into agreements for the next several years with ComEd and PECO to sell the power needed to meet the demand of their customers. These agreements provide a mechanism to enhance stability in Generation's earnings and limit its exposure to the negative effects of wholesale markets.

The commencement of commercial operation of new generating facilities in the regional markets where Generation has facilities or contracts for power, such as the Midwest, Mid-Atlantic, Northeast and South (including certain sections of Texas), would likely decrease wholesale power market prices in those regions, which could have a negative effect on Generation's business and results of operations.

Generation's financial performance may be affected by the marketing, trading and risk management activities of Power Team.

Generation's wholesale marketing unit, Power Team,

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•: uses Generation's energy generation portfolio, transmission rights and its power marketing expertise to manage delivery of energy to wholesale customers, including ComEd and PECO, under long-term and short-term contracts,
•: participates in the wholesale energy market to hedge its 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.

Power Team has substantial 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 ComEd and PECO. 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 Generation's capacity not used to meet customer demand, in the wholesale energy market.

Power Team began proprietary trading activities in 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 earnings. Power Team will 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.

Power Team has managed to avoid the recent managerial problems experienced in the energy trading industry through the strict adherence to prudent risk management practices. However, 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 Power Team's trading operations in the future.

Generation depends on counterparties fulfilling their obligations.

Generation's trading, marketing and contracting operations are exposed to the risk that counterparties, which owe Generation money or energy as a result of market transactions, will not perform their obligations. In order to evaluate the viability of Generation's counterparties, Generation has implemented credit risk management procedures designed to mitigate the risks associated with these transactions. Energy supplied by third-party generators, including AmerGen and Sithe, under long-term agreements represents a significant portion of Generation's overall capacity. These third-party generators face operational risks such as those that Generation faces, and their ability to perform also depends on their financial condition. In the event the counterparties to these arrangements fail to perform, Generation might be forced to honor the underlying commitment at then-current market prices and incur additional losses, to the extent of amounts, if any, already paid to the counterparties. Generation manages counterparty credit risk through established policies, including counterparty credit limits, and in some cases, requiring deposits and letters of credit to be posted by certain counterparties. Generation's counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Generation has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties. These agreements reduce Generation's exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. The credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

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See the Credit Risk section in ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk—Generation for further discussions on specific credit risk matters such as Generation's potential counterparty exposures, including Dynegy Inc. (Dynegy).

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

Regional Transmission Organizations/Standard Market Design. Generation is dependent on wholesale energy markets and open transmission access and rights by which it delivers power to its wholesale customers, including ComEd and PECO. Generation uses the wholesale regional energy markets to sell power that it does not need to satisfy long-term contractual obligations, to meet long-term obligations not provided by its own resources, and to take advantage of price opportunities.

Wholesale spot markets have only been implemented in certain areas of the country and each market has unique features that may create trading barriers between the markets. Although FERC has proposed initiatives, including Order 2000 and the proposed SMD rule, to encourage the development of large regional, uniform markets and to eliminate trade barriers, these initiatives have not yet led to the development of such markets all across the country. PJM's market strongly resembles FERC's proposal, and both the New England Independent System Operator (NE-ISO) and the New York Independent System operator (NYISO) are implementing market reforms. Generation strongly encourages the development of standardized energy markets and support FERC's standardization efforts as being essential to wholesale competition in the energy industry and to Generation's ability to compete on a national basis and to meet its long-term contractual commitments efficiently.

Approximately 26% of Generation's current generation resources are located in the region encompassed by PJM. If the PJM market is expanded to the Midwest, 82% of Generation's current assets will be located within the expanded market. The PJM market has been the most liquid regional market and is largely consistent with the standard market design proposed by FERC. Generation's future results of operations may be impacted by the successful expansion of that market to the Midwest and the implementation of any market changes mandated by FERC.

Provider of Last Resort. As noted, ComEd and PECO have a POLR obligation that they have largely assigned to Generation through the full requirements contracts that it has with Generation. Currently both ComEd and PECO have entered into PPAs with Generation to provide 100% of their respective energy requirements. ComEd's PPA with Generation is for 100% of its required load through 2004 at fixed prices, and in 2005 and 2006 it equals 100% of the output of ComEd's former nuclear plants, now owned by Generation at market based prices. PECO's PPA with Generation is a full load requirements contract through 2010. Exelon intends to revise the PPA between ComEd and Generation to be a full requirements contract in 2005 and 2006. Additionally, the PPAs between Generation, ComEd and PECO may be extended beyond their current expiration dates. ComEd and PECO continue to work on resolution of the POLR issues with their respective state regulatory commissions and other market participants.

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

Generation's business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects. As mentioned previously, 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. The inability to effectively manage the capital projects, such as the Sithe New England facilities, could adversely affect Generation's results from operations.

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Capital Markets/Financing Environment

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

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

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

•: credit availability from banks and other financial institutions,
•: maintenance of acceptable credit ratings (see Generation's Credit Ratings above in the credit issues section of Liquidity and Capital Resources),
•: investor confidence in Generation and Exelon,
•: investor confidence in regional wholesale power markets,
•: general economic and capital market conditions,
•: the success of current projects, and
•: the perceived quality of new projects.

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

Generation has investment grade ratings and has been successful in raising capital, which has been used to further its business initiatives. Also, from time to time, Generation enters into energy commodity and other contracts that require the maintenance of investment grade ratings. Failure to maintain investment grade ratings would require Generation to incur higher financing costs and would allow, but not in most instances require, counterparties to energy commodity contracts to terminate the contracts and settle the transaction. Also, the failure to maintain investment grade ratings would restrict Generation's access to the wholesale energy markets.

Equity market performance affects Generation's decommissioning trust funds and 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 and the eventual nuclear generation station decommissioning requirements. 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 and nuclear decommissioning trusts in order to achieve the best return possible in conjunction with Exelon's overall risk management practices and diversified approach to investment. See ITEM 7. ComEd, PECO,

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Gneration—Critical Accounting Estimates section that more fully describes the quantitative financial statement effects of changes in the equity markets on the nuclear decommissioning trust funds and benefit plan assets.

Other

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

Generation's businesses are subject to extensive environmental regulation by local, state and Federal authorities. These laws and regulations affect the manner in which Generation conducts its operations and makes its capital expenditures. These regulations affect how Generation handles air and water emissions and solid waste disposal and are an important aspect of Generation's operations. In addition, Generation is subject to liability under these laws for the costs of remediating environmental contamination of property now or formerly owned by ComEd or PECO and of property contaminated by hazardous substances generated. Generation believes that it has a responsible environmental management and compliance program; however, Generation has incurred and expects to incur significant costs related to environmental compliance and site remediation and clean-up. Generation 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, Generation's reserve for environmental investigation and remediation costs was $15 million, exclusive of decommissioning liabilities. Generation has accrued and will continue to accrue amounts that management believes are prudent to cover these environmental liabilities, but Generation cannot predict with any certainty whether these amounts will be sufficient to cover its environmental liabilities. Generation cannot predict whether it will incur other significant liabilities for any additional investigation and remediation costs at additional sites not currently identified by Generation, environmental agencies or others, or whether such costs will be recoverable from third parties.

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

Security. Generation does not fully know the impact that future terrorist attacks or threats of terrorism may have on its industry in general and on itself in particular. The events of September 11, 2001 have affected Generation's operating procedures and costs. Generation has initiated security measures to safeguard its employees and critical operations and is actively participating in industry initiatives to identify methods to maintain the reliability of its 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, Generation 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 Generation's ability to continue to operate under difficult times.

Nuclear liability insurance. The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. 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. As required by the Price-Anderson Act, Generation carries nuclear liability insurance in the maximum available amount (currently $300 million per site). Claims exceeding that amount are covered through mandatory participation in a financial protection pool. The Price-Anderson Act expired on August 1,

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2002, but existing facilities, such as those owned and operated by Generation, remain covered. The provisions of the Price-Anderson Act related to commercial facilities have been extended through 2003. The extension affects facilities obtaining NRC operating licenses in 2003. Existing facilities are unaffected by the extension.

Other insurance. In addition to nuclear liability insurance, Generation also 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. Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained.

A claim that exceeds the amounts available under Generation's property damage and liability insurance would negatively affect its results of operations. NEIL, a mutual insurance company to which Generation belongs, provides property and business interruption insurance for its nuclear operations. In recent years, NEIL has made distributions to its members. Generation's distribution for 2002 was $40 million, which was recorded as a reduction to O&M expense on its Consolidated Statements of Income. Generation cannot predict the level of future distributions.

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

Any military strikes or sustained military campaign may affect Generation's operations in unpredictable ways, such as increased security measures and disruptions of fuel supplies and markets, particularly oil and LNG. 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 Generation'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 Generation's revenues or restrict its future growth. Instability in the financial markets as a result of war may affect Generation's ability to raise capital.

The introduction of new technologies could increase competition within Generation'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 Generation'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.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Exelon

The information required by this Item is incorporated herein by reference to the information appearing under the subheading "Quantitative and Qualitative Disclosures About Market Risk" under "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.

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ComEd

ComEd is exposed to market risks associated with credit, interest rates and commodity price. The inherent risk in market sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, counterparty credit, and interest rates. Exelon's corporate Risk Management Committee (RMC) sets forth risk management philosophy and objectives for Exelon and its subsidiaries through a corporate policy, and establishes procedures for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of derivative activity and risk exposures. The RMC is chaired by Exelon's chief risk officer and includes the chief financial officer, general counsel, treasurer, vice president of corporate planning and officers from each of the business units. The RMC reports to the board of directors on the scope of ComEd's derivative activities.

Credit Risk

ComEd is obligated to provide service to all electric customers within its franchised territories and the resulting broad customer base mitigates ComEd's credit risk exposure. For the year ended December 31, 2002, ComEd's ten largest customers represented approximately 3% of its retail electric revenues. ComEd manages credit risk using credit and collection policies which are regulated by the ICC.

Interest Rate Risk

ComEd uses a combination of fixed rate and variable rate debt to reduce interest rate exposure. Interest rate swaps may be used to adjust exposure when deemed appropriate based upon market conditions. ComEd also utilizes forward-starting interest rate swaps and treasury rate locks to lock in interest rate levels in anticipation of future financing. These strategies are employed to maintain the lowest cost of capital. As of December 31, 2002, a hypothetical 10% increase in the interest rates associated with variable rate debt would result in a $1 million decrease in pre-tax earnings for 2003.

ComEd has entered into fixed-to-floating interest rate swaps in order to maintain its targeted percentage of variable rate debt, associated with debt issuances in the aggregate amount of $485 million fixed-rate obligation. At December 31, 2002, these interest rate swaps had an aggregate fair market value of $41 million based on the present value difference between the contract and market rates at December 31, 2002.

ComEd has forward-starting interest rate swaps in the aggregate amount of $630 million to lock in interest rate levels in anticipation of future financings. At December 31, 2002, these interest rate swaps, designated as cash flow hedges, had a fair market value exposure of $52 million. As it remained probable that the debt issuances, the forecasted future transactions these swaps were hedging, would occur, although the issuances had been delayed, ComEd continued to account for these interest rate swap transactions as hedges. In connection with ComEd's January 22, 2003 issuance of $700 million in First Mortgage Bonds, ComEd settled swaps, in the aggregate notional amount of $550 million, for a payment of $43 million, which will be recorded as a regulatory asset and amortized over the life of the debt issuance.

In 2002, ComEd settled $450 million of forward-starting interest rate swaps and paid $10 million to the counterparties.

The aggregate fair value of the interest rate swaps, designated as fair value hedges, that would have resulted from a hypothetical 50 basis point decrease in the spot yield at December 31, 2002 is estimated to be $49 million. If these derivative instruments had been terminated at December 31, 2002, this estimated fair value represents the amount that would be paid by the counterparties to ComEd.

The aggregate fair value of the interest rate swaps, designated as fair value hedges, that would have resulted from a hypothetical 50 basis point increase in the spot yield at December 31, 2002 is

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estimated to be $33 million. If these derivative instruments had been terminated at December 31, 2001, this estimated fair value represents the amount to be paid by the counterparties to ComEd.

The aggregate fair value exposure of the interest rate swaps, designated as cash flow hedges, that would have resulted from a hypothetical 50 basis point decrease in the spot yield at December 31, 2002 is estimated to be $69 million. If these derivative instruments had been terminated at December 31, 2002, this estimated fair value represents the amount that would be paid by ComEd to the counterparties.

The aggregate fair value exposure of the interest rate swaps, designated as fair value hedges, that would have resulted from a hypothetical 50 basis point increase in the spot yield at December 31, 2002 is estimated to be $36 million. If these derivative instruments had been terminated at December 31, 2002, this estimated fair value represents the amount to be paid by ComEd to the counterparties.

Commodity Price Risk

As part of the 2001 corporate restructuring, ComEd entered into a PPA with Generation to meet its retail customer obligations at fixed prices. ComEd's principal exposure to commodity price risk is in relation to revenues collected from customers who elect the PPO at market-based prices, and CTC revenues which are calculated to provide the customer with a credit for the market price for electricity. ComEd has performed a sensitivity analysis to determine the net impact of a 10% decrease in the average around-the-clock market price of electricity. Because the decrease in revenues from customers electing the PPO is significantly offset by increased CTC revenues, ComEd does not believe that its exposure to such a market price decrease would be material.

PECO

PECO is exposed to market risks associated with credit and interest rates. The inherent risk in market sensitive instruments and positions is the potential loss arising from adverse changes in counterparty credit and interest rates. Exelon's corporate RMC sets forth risk management philosophy and objectives through a corporate policy, and establishes procedures for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of derivative activity and risk exposures. The RMC is chaired by the chief risk officer and includes the chief financial officer, general counsel, treasurer, vice president of corporate planning and officers from each of the business units. The RMC reports to the board of directors on the scope of Exelon's derivative activities. As a result of the PPA with Generation, PECO does not believe it is subject to material commodity price risk.

Credit Risk

Credit risk for PECO is managed by its credit and collection policies, which is consistent with state regulatory requirements. PECO is obligated to provide service to all electric customers within its franchised service territories. As a result, PECO has a broad customer base. For the year ended December 31, 2002, PECO's ten largest customers represented approximately 8% of its retail electric revenues. PECO records a provision for uncollectible accounts, based upon historical experience and third-party studies, to provide for the potential loss from nonpayment by these customers.

Under the Competition Act, licensed entities, including alternative electric generating suppliers, may act as agents to provide a single bill and provide associated billing and collection services to retail customers located in PECO's retail electric service territory. Currently, there are no third parties providing billing of PECO's charges to customers or advanced metering. However, if this occurs, PECO would be subject to credit risk related to the ability of the third parties to collect such receivables from the customers.

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Interest Rate Risk

PECO uses a combination of fixed rate and variable rate debt to reduce interest rate exposure. Interest rate swaps may be used to adjust exposure when deemed appropriate based upon market conditions. PECO also utilizes forward-starting interest rate swaps and treasury rate locks to lock in interest rate levels in anticipation of future financing. As of December 31, 2002, a hypothetical 10% increase in the interest rates associated with variable rate debt would not have a material impact on pre-tax earnings for 2003.

During 2002, PECO entered into forward-starting interest rate swaps, with an aggregate notional amount of $200 million, in anticipation of the issuance of debt at PECO. These interest rate swaps were designated as cash flow hedges. In connection with bond issuances in 2002, PECO settled these forward- starting interest rate swaps resulting in a $5 million pre-tax loss recorded in OCI, which is being amortized over the life of the related debt.

PECO has entered into interest rate swaps to manage interest rate exposure associated with the floating rate series of transition bonds issued to securitize PECO's stranded cost recovery. At December 31, 2002, these interest rate swaps had an aggregate fair market value exposure of $22 million based on the present value difference between the contract and market rates at December 31, 2002.

PECO also has interest rate swaps in place to satisfy counterparty credit requirements in regards to the floating rate series of transition bonds which are mirror swaps of each other. These swaps are not designated as cash flow hedges; therefore, they are required to be marked-to-market if there is a difference in their values. Since these swaps offset each other, a mark-to-market adjustment is not expected to occur.

The aggregate fair value exposure of the interest rate swaps that would have resulted from a hypothetical 50 basis point decrease in the spot yield at December 31, 2002 is estimated to be $23 million. If these derivative instruments had been terminated at December 31, 2002, this estimated fair value represents the amount that would be paid by PECO to the counterparties.

The aggregate fair value exposure of the interest rate swaps that would have resulted from a hypothetical 50 basis point increase in the spot yield at December 31, 2002 is estimated to be $20 million. If these derivative instruments had been terminated at December 31, 2002, this estimated fair value represents the amount to be paid by PECO to the counterparties.

Generation

Generation is exposed to market risks associated with commodity price, credit, interest rates and equity prices. The inherent risk in market sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, counterparty credit, interest rates and equity security prices. Exelon's corporate RMC sets forth risk management philosophy and objectives through a corporate policy, and establishes procedures for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of derivative activity and risk exposures. The RMC is chaired by Exelon's chief risk officer and includes the chief financial officer, general counsel, treasurer, vice president of corporate planning and officers from each of the Exelon business units. The RMC reports to the Exelon Board of Directors on the scope of Generation's derivative and risk management activities.

Commodity Price Risk

Commodity price risk is associated with market price movements resulting from excess or insufficient generation, changes in fuel costs, market liquidity and other factors. Trading activities and non-trading marketing activities include the purchase and sale of electric capacity and energy and fossil

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fuels, including oil, gas, coal and emission allowances. The availability and prices of energy and energy-related commodities are subject to fluctuations due to factors such as weather, governmental environmental policies, changes in supply and demand, state and Federal regulatory policies and other events.

Normal Operations and Hedging Activities

Electricity available from Generation's owned or contracted generation supply in excess of its obligations to customers, including Energy Delivery's retail load, is sold into the wholesale markets. To reduce price risk caused by market fluctuations, Generation enters into physical contracts as well as derivative contracts, including forwards, futures, swaps, and options, with approved counterparties to hedge its anticipated exposures. The maximum length of time over which cash flows related to energy commodities are currently being hedged is 4 years. Generation has an estimated 90% hedge ratio in 2003 for its energy marketing portfolio. This hedge ratio represents the percentage of Generation's forecasted aggregate annual generation supply that is committed to firm sales, including sales to ComEd and PECO's retail load. ComEd's and PECO's retail load assumptions are based on forecasted average demand. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand, and energy market option volatility and actual loads. During peak periods the amount hedged declines to meet the commitment to ComEd and PECO. Market price risk exposure is the risk of a change in the value of unhedged positions. Absent any opportunistic efforts to mitigate market price exposure, the estimated market price exposure for Generation's non-trading portfolio associated with a ten percent reduction in the annual average around-the-clock market price of electricity is an approximately $37 million decrease in net income. This sensitivity assumes a 90% hedge ratio and that price changes occur evenly throughout the year and across all markets. The sensitivity also assumes a static portfolio. Generation expects to actively manage its portfolio to mitigate market price exposure. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation's portfolio.

Proprietary Trading

Activities. Generation began to use financial contracts for proprietary trading purposes in the second quarter of 2001. Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure. These activities are accounted for on a mark-to-market basis. The proprietary trading activities are a complement to Generation's energy marketing portfolio and represent a very small portion of its overall energy marketing activities. For example, the limit on open positions in electricity for any forward month represents less than 1% of Generation's owned and contracted supply of electricity. The trading portfolio is subject to stringent risk management limits and policies, including volume, stop-loss and value-at-risk limits.

Generation's energy contracts are accounted for under SFAS No. 133. Most non-trading contracts qualify for the normal purchases and normal sales exemption to SFAS No. 133 discussed in Critical Accounting Estimates. Those that do not are recorded as assets or liabilities on the balance sheet at fair value. Changes in the fair value of qualifying hedge contracts are recorded in OCI, and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS No. 133 and the ineffective portion of hedge contracts are recognized in earnings on a current basis.

The following detailed presentation of the trading and non-trading marketing activities at Generation is included to address the recommended disclosures by the energy industry's Committee of Chief Risk Officers. Generation does not consider its proprietary trading to be a significant activity in its business; however, Generation believes it is important to include these risk management disclosures.

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The following table describes the drivers of Generation's energy trading and marketing business and gross margin included in the income statement for the year ended December 31, 2002. Normal operations and hedging activities represent the marketing of electricity available from Generation's owned or contracted generation, including ComEd and PECO's retail load, sold into the wholesale market. As the information in this table highlights, mark-to-market activities represent a small portion of the overall gross margin for Generation. Accrual activities, including normal purchases and sales, account for the majority of the gross margin. The mark-to-market activities reported here are those relating to changes in fair value due to external movement in prices. Further delineation of gross margin by the type of accounting treatment typically afforded each type of activity is also presented (i.e., mark-to-market vs. accrual accounting treatment).

		Normal Operations and Hedging Activities(a)			Proprietary Trading			Total
Mark-to-Market Activities:
Unrealized Mark-to-Market Gain/(Loss)
	Origination Unrealized Gain/(Loss) at Inception	$	—		$	—		$	—
	Changes in Fair Value Prior to Settlements		26			(29	)		(3	)
	Changes in Valuation Techniques and Assumptions		—			—			—
	Reclassification to Realized at Settlement of Contracts		(20	)		20			—

	Total Change in Unrealized Fair Value		6			(9	)		(3	)
Realized Net Settlement of Transactions Subject to Mark-to-Market			20			(20	)		—

Total Mark-to-Market Activities Gross Margin		$	26		$	(29	)	$	(3	)

Accrual Activities:
Accrual Activities Revenue		$	6,785		$	—		$	6,785
Hedge Gains/(Losses) Reclassified from OCI			76			—			76

	Total Revenue—Accrual Activities		6,861			—			6,861

Purchased Power and Fuel			4,230			—			4,230
Hedges of Purchased Power and Fuel Reclassified from OCI			23			—			23

	Total Purchased Power and Fuel		4,253			—			4,253

	Total Accrual Activities Gross Margin		2,608			—			2,608

Total Gross Margin		$	2,634		$	(29	)	$	2,605	(b)

(a): Normal Operations and Hedging Activities only include derivative contracts Power Team enters into to hedge anticipated exposures related to its owned and contracted generation supply, but excludes its owned and contracted generating assets.
(b): Total Gross Margin represents revenue, net of purchased power and fuel expense for Generation.

The following table provides detail on changes in Generation's mark-to-market net asset or liability balance sheet position from January 1, 2002 to December 31, 2002. It indicates the drivers behind changes in the balance sheet amounts. This table will incorporate the mark-to-market activities that are immediately recorded in earnings, as shown in the previous table, as well as the settlements from OCI

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to earnings and changes in fair value for the hedging activities that are recorded in Accumulated Other Comprehensive Income on the Consolidated Balance Sheets.

	Normal Operations and Hedging Activities			Proprietary Trading			Total
Total Mark-to-Market Energy Contract Net Assets at January 1, 2002	$	78		$	14		$	92
Total Change in Fair Value during 2002 of Contracts Recorded in Earnings		26			(29	)		(3	)
Reclassification to Realized at Settlement of Contracts Recorded in Earnings		(20	)		20			—
Reclassification to Realized at Settlement from OCI		(53	)		—			(53	)
Effective Portion of Changes in Fair Value—Recorded in OCI		(210	)		—			(210	)
Purchase/Sale of Existing Contracts or Portfolios Subject to Mark-to-Market		11			—			11

Total Mark-to-Market Energy Contract Net Assets (Liabilities) at December 31, 2002	$	(168	)	$	5		$	(163	)

The following table details the balance sheet classification of the Mark-to-Market Energy Contract Net Assets recorded as of December 31, 2002:

		Normal Operations and Hedging Activities			Proprietary Trading			Total
Current Assets		$	186		$	6		$	192
Noncurrent Assets			46			—			46

	Total Mark-to-Market Energy Contract Assets		232			6			238

Current Liabilities			(276	)		—			(276	)
Noncurrent Liabilities			(124	)		(1	)		(125	)

	Total Mark-to-Market Energy Contract Liabilities		(400	)		(1	)		(401	)

Total Mark-to-Market Energy Contract Net Assets (Liabilities)		$	(168	)	$	5		$	(163	)

The majority of Generation's contracts are non-exchange traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter, on-line exchanges. Prices reflect the average of the bid-ask midpoint prices obtained from all sources that Generation believes provide the most liquid market for the commodity. The terms for which such price information is available varies by commodity, by region and by product. The remainder of the assets represents contracts for which external valuations are not available, primarily option contracts. These contracts are valued using the Black model, an industry standard option valuation model. The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2002 and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts it holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.

The following table, which presents maturity and source of fair value of mark-to-market energy contract net assets, provides two fundamental pieces of information. First, the table provides the source of fair value used in determining the carrying amount of Generation's total mark-to-market asset or

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liability. Second, this table provides the maturity, by year, of Generation's net assets/liabilities, giving an indication of when these mark-to-market amounts will settle and generate or require cash.

		Maturities within
		2003			2004			2005			2006			2007			2008 and Beyond		Total Fair Value
Normal Operations, qualifying cash flow hedge contracts(1):
	Prices provided by other external sources	$	(124	)	$	(48	)	$	(9	)	$	(5	)	$	—		$	—	$	(186	)

	Total	$	(124	)	$	(48	)	$	(9	)	$	(5	)	$	—		$	—	$	(186	)

Normal Operations, other derivative contracts(2):
	Actively quoted prices	$	26		$	4		$	—		$	—		$	—		$	—	$	30
	Prices provided by other external sources		—			3			2			2			—			—		7
	Prices based on model or other valuation methods		7			(11	)		(4	)		(9	)		(2	)		—		(19	)

	Total	$	33		$	(4	)	$	(2	)	$	(7	)	$	(2	)	$	—	$	18

Proprietary Trading, other derivative contracts(3):
	Actively quoted prices	$	(4	)	$	—		$	—		$	—		$	—		$	—	$	(4	)
	Prices provided by other external sources		6			(3	)		—			—			—			—		3
	Prices based on model or other valuation methods		5			1			—			—			—			—		6

	Total	$	7		$	(2	)	$	��		$	—		$	—		$	—	$	5

Average tenor of proprietary trading portfolio(4)																				1.5 years

(1): Mark-to-market gains and losses on contracts that qualify as cash flow hedges are recorded in other comprehensive income.
(2): Mark-to-market gains and losses on other non-trading derivative contracts that do not qualify as cash flow hedges are recorded in earnings.
(3): Mark-to-market gains and losses on trading contracts are recorded in earnings.
(4): Following the recommendations of the Committee of Chief Risk Officers, the average tenor of the proprietary trading portfolio measures the average time to collect value for that portfolio. Generation measures the tenor by separating positive and negative mark-to-market values in its proprietary trading portfolio, estimating the mid-point in years for each and then reporting the highest of the two mid-points calculated. In the event that this methodology resulted in significantly different absolute values of the positive and negative cash flow streams, Generation would use the mid-point of the portfolio with the largest cash flow stream as the tenor.

The table below provides details of effective cash flow hedges under SFAS No. 133 included in the balance sheet as of December 31, 2002. The data in the table gives an indication of the magnitude of SFAS No. 133 hedges Generation has in place, however, given that under SFAS No. 133 not all hedges are recorded in OCI, the table does not provide an all-encompassing picture of Generation's hedges. The table also includes a roll-forward of Accumulated Other Comprehensive Income on the Consolidated Balance Sheets related to cash flow hedges for the year ended December 31, 2002, providing insight into the drivers of the changes (new hedges entered into during the period and

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changes in the value of existing hedges). Information related to energy merchant activities is presented separately from interest rate hedging activities.

	Total Cash Flow Hedge Other Comprehensive Income Activity, Net of Income Tax
	Power Team Normal Operations and Hedging Activities			Interest Rate and Other Hedges(1)			Total Cash Flow Hedges
Accumulated OCI, January 1, 2002	$	47		$	1		$	48
Changes in Fair Value		(128	)		(9	)		(137	)
Reclassifications from OCI to Net Income		(33	)		—			(33	)

Accumulated OCI Derivative Gain/(Loss) at December 31, 2002	$	(114	)	$	(8	)	$	(122	)

(1): Includes interest rate hedges at Generation.

Generation uses a Value-at-Risk (VaR) model to assess the market risk associated with financial derivative instruments entered into for proprietary trading purposes. The measured VaR represents an estimate of the potential change in value of Generation's proprietary trading portfolio.

The VaR estimate includes a number of assumptions about current market prices, estimates of volatility and correlations between market factors. These estimates, however, are not necessarily indicative of actual results, which may differ because actual market rate fluctuations may differ from forecasted fluctuations and because the portfolio may change over the holding period.

Generation estimates VaR using a model based on the Monte Carlo simulation of commodity prices that captures the change in value of forward purchases and sales as well as option values. Parameters and values are back tested daily against daily changes in mark-to-market value for proprietary trading activity. VaR assumes that normal market conditions prevail and that there are no changes in positions. Generation uses a 95% confidence interval, one-day holding period, one-tailed statistical measure in calculating its VaR. This means that Generation may state that there is a one in 20 chance that if prices move against its portfolio positions, its pre-tax loss in liquidating its portfolio in a one-day holding period would exceed the calculated VaR. To account for unusual events and loss of liquidity, Generation uses stress tests and scenario analysis.

For financial reporting purposes only, Generation calculates several other VaR estimates. The higher the confidence interval, the less likely the chance that the VaR estimate would be exceeded. A longer holding period considers the effect of liquidity in being able to actually liquidate the portfolio. A two-tailed test considers potential upside in the portfolio in addition to the potential downside in the

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portfolio considered in the one-tailed test. The following table provides the VaR for all proprietary trading positions of Generation as of December 31, 2002.

		Proprietary Trading VaR
95% Confidence Level, One-Day Holding Period, One-Tailed
	Period End	$	0.2
	Average for the Period		1.4
	High		5.0
	Low		0.2
95% Confidence Level, Ten-Day Holding Period, Two-Tailed
	Period End	$	0.3
	Average for the Period		1.5
	High		5.3
	Low		0.1
99% Confidence Level, One-Day Holding Period, Two-Tailed
	Period End	$	0.9
	Average for the Period		4.6
	High		16.7
	Low		0.4

Credit Risk

Generation has credit risk associated with counterparty performance on energy contracts which includes, but is not limited to, the risk of financial default or slow payment. Generation manages counterparty credit risk through established policies, including counterparty credit limits, and in some cases, requiring deposits and letters of credit to be posted by certain counterparties. Generation's counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Generation has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Generation's exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. The credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

The following table provides information on Generation's credit exposure, net of collateral, as of December 31, 2002. Credit exposure, in the below table, is defined as net accounts receivable as well as any net in-the-money forward mark-to-market exposure. Exposures are shown net, if such agreements with counterparties are in place. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company's credit risk by credit rating of the counterparties. The

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figures in the table below do not include sales to Generation's affiliates or exposure through Independent System Operators (ISOs) which are discussed below.

Rating		Total Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number Of Counterparties Greater than 10% of Net Exposure	Net Exposure Of Counterparties Greater than 10% of Net Exposure
Investment Grade		$	156	$	—	$	156	2	$	71
Split Rating			—		—		—	—		—
Non-Investment Grade			17		11		6	—		—
No External Ratings
	Internally Rated—Investment Grade		27		4		23	4		16
	Internally Rated—Non-Investment Grade		4		2		2	—		—

Total		$	204	$	17	$	187	6	$	87

		Maturity of Credit Risk Exposure
Rating		Less than 2 Years		2-5 Years		Exposure Greater than 5 Years		Total Exposure Before Credit Collateral
Investment Grade		$	117	$	39	$	—	$	156
Split Rating			—		—		—		—
Non-Investment Grade			17		—		—		17
No External Ratings
	Internally Rated—Investment Grade		27		—		—		27
	Internally Rated—Non-Investment Grade		4		—		—		4

Total		$	165	$	39	$	—	$	204

Generation is a counterparty to Dynegy in various energy transactions. In early July 2002, the credit ratings of Dynegy were downgraded to below investment grade by two credit rating agencies. As of December 31, 2002, Generation had a net receivable from Dynegy of approximately $3 million and, consistent with the terms of the existing credit arrangement, has received collateral in support of this receivable. Generation also has credit risk associated with Dynegy through Generation's equity investment in Sithe. Sithe is a 60% owner of the Independence generating station (Independence), a 1,040-MW gas-fired qualified facility that has an energy-only long-term tolling agreement with Dynegy, with a related financial swap arrangement. As of December 31, 2002, Sithe had recognized an asset on its balance sheet related to the fair market value of the financial swap agreement with Dynegy that is marked to market under the terms of SFAS No. 133. If Dynegy is unable to fulfill the terms of this agreement, Sithe would be required to impair this financial swap asset. Generation estimates, as a 49.9% owner of Sithe, that the impairment would result in an after-tax reduction of its earnings of approximately $10 million.

In addition to the impairment of the financial swap asset, if Dynegy were unable to fulfill its obligations under the financial swap agreement and the tolling agreement, Generation would likely incur a further impairment associated with Independence. Depending upon the timing of Dynegy's failure to fulfill its obligations and the outcome of any restructuring initiatives, Generation could realize an after-tax charge of between $0 and $130 million. In the event of a sale of Generation's investment in Sithe to a third party, proceeds from the sale could be negatively impacted between $65 million and $100 million (after-tax).

Additionally, the future economic value of AmerGen's PPA with Illinois Power Company, a subsidiary of Dynegy, could be impacted by events related to Dynegy's financial condition.

142

Generation participates in the following established, real-time energy markets, which are administered by ISOs: PJM, New England ISO, New York ISO, California ISO, Midwest ISO, Inc., Southwest Power Pool, Inc. and Texas, which is administered by the Electric Reliability Council of Texas. In these areas, power is traded through bilateral agreements between buyers and sellers and in certain of these areas power is traded on the spot markets that are operated by the ISOs. For sales into the spot markets administered by the ISOs, the ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the ISOs may under certain circumstances require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on Generation's financial condition, results of operations or net cash flows.

Interest Rate Risk

Generation uses a combination of fixed rate and variable rate debt to reduce interest rate exposure. Generation also uses interest rate swaps when deemed appropriate to adjust exposure based upon market conditions. These strategies are employed to achieve a lower cost of capital. As of December 31, 2002, a hypothetical 10% increase in the interest rates associated with variable rate debt would result in a $4 million decrease in pre-tax earnings for 2003.

Under the terms of the Sithe Boston Generation, LLC (SBG) credit facility, SBG is required to effectively fix the interest rate on 50% of borrowings under the facility through its maturity in 2007. As of December 31, 2002, Generation has entered into interest rate swap agreements, which have effectively fixed the interest rate on $861 million of notional principal, or 83% of borrowings outstanding under the SBG credit facility at December 31, 2002. The fair market value exposure of these swaps, designated as cash flow hedges, is $92 million.

The aggregate fair value exposure of the interest rate swaps designated as cash flow hedges that would have resulted from a hypothetical 50 basis point decrease in the spot yield at December 31, 2002 is estimated to be $108 million. If the derivative instruments had been terminated at December 31, 2002, this estimated fair value represents the amount Generation would pay to the counterparties.

The aggregate fair value exposure of the interest rate swaps designated as cash flow hedges that would have resulted from a hypothetical 50 basis point increase in the spot yield at December 31, 2002 is estimated to be $76 million. If the derivative instruments had been terminated at December 31, 2002, this estimated fair value represents the amount Generation would pay to the counterparties.

Equity Price Risk

Generation maintains trust funds, as required by the NRC, to fund certain costs of decommissioning its nuclear plants. As of December 31, 2002, Generation's decommissioning trust funds are reflected at fair value on its Consolidated Balance Sheet. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate for inflationary increases in decommissioning costs. However, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed rate, fixed income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with its nuclear decommissioning trust fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $172 million reduction in the fair value of the trust assets. See Defined Benefit Pension and Other Postretirement Welfare Benefits section of ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Generation—Critical Accounting Estimates for information regarding the pension and other postretirement benefit trust assets.

143

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Exelon

The information required by this Item is incorporated herein by reference to the Consolidated Statements of Income for the years 2002, 2001 and 2000; Consolidated Statements of Cash Flows for the years 2002, 2001 and 2000; Consolidated Balance Sheets as of December 31, 2002 and 2001; Consolidated Statements of Changes in Shareholders' Equity for the years 2002, 2001 and 2000 and Consolidated Statements of Comprehensive Income for the years 2002, 2001 and 2000; and Notes to Consolidated Financial Statements appearing in Exhibit 99-4 to Exelon's Current Report on Form 8-K dated February 21, 2003.

144

ComEd

Report of Independent Accountants

To the Shareholders and Board of Directors of
Commonwealth Edison Company:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(2)(i) present fairly, in all material respects, the financial position of Commonwealth Edison Company and Subsidiary Companies (ComEd) at December 31, 2002 and 2001, and the results of their operations and their cash flows for the years ended December 31, 2002 and 2001 and for the periods from October 20, 2000 to December 31, 2000 and from January 1, 2000 to October 19, 2000, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2)(ii) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of ComEd's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 3 to the consolidated financial statements, effective October 20, 2000, Exelon Corporation acquired Unicom Corporation, the parent company of ComEd at that date, in a business combination accounted for as a purchase. As a result of the acquisition, the consolidated financial information for the period after the acquisition is presented on a different cost basis than that for the periods before the acquisition and therefore, is not comparable. As discussed in Note 2 to the consolidated financial statements, as part of a corporate restructuring undertaken on January 1, 2001 by Exelon Corporation, the parent company of ComEd, all of ComEd's generation-related and certain other operations, assets and liabilities of ComEd were transferred to affiliated companies of ComEd.

As discussed in Note 1 to the consolidated financial statements, ComEd changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001.

As discussed in Note 4 to the consolidated financial statements, ComEd changed its method of accounting for goodwill effective January 1, 2002.

PricewaterhouseCoopers LLP

Chicago, Illinois
January 29, 2003, except for Note 19 for which the date is March 17, 2003.

145

Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Income

									For the periods
			For the Years Ended December 31,						Oct. 20- Dec. 31,			I I	Jan. 1- Oct. 19,
			2002			2001			2000			I I	2000
			(in millions)
Operating Revenues												I
	Operating Revenues		$	6,061		$	6,125		$	1,297		I	$	5,625
	Operating Revenues from Affiliates			63			81			13		I		77
												I
Total Operating Revenues				6,124			6,206			1,310		I		5,702
												I
Operating Expenses												I
	Purchased Power and Fuel			26			14			322		I		1,655
	Purchased Power from Affiliate			2,559			2,656			—		I		—
	Operating and Maintenance			828			846			423		I		1,653
	Operating and Maintenance from Affiliates			136			135			—		I		—
	Merger-Related Costs			—			—			14		I		53
	Depreciation and Amortization			522			665			130		I		868
	Taxes Other Than Income			287			296			83		I		425
												I
Total Operating Expenses				4,358			4,612			972		I		4,654
												I
Operating Income				1,766			1,594			338		I		1,048
												I
Other Income and Deductions												I
	Interest Expense			(480	)		(555	)		(127	)	I		(475	)
	Interest Expense from Affiliates			(4	)		(10	)		—		I		—
	Distributions on Company-Obligated Mandatorily											I
	Redeemable Preferred Securities of Subsidiary Trusts Holding											I
	Solely the Company's Subordinated Debt Securities			(30	)		(30	)		(6	)	I		(24	)
	Interest Income from Affiliates			31			79			29		I		150
	Other, Net			13			35			2		I		127
												I
		Total Other Income and Deductions		(470	)		(481	)		(102	)	I		(222	)
												I
Income Before Income Taxes				1,296			1,113			236		I		826
Income Taxes				506			506			103		I		227
												I
Net Income				790			607			133		I		599
Preferred and Preference Stock Dividends				—			—			—		I		3
												I
Net Income on Common Stock			$	790		$	607		$	133		I	$	596
												I

See Notes to Consolidated Financial Statements

146

Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Cash Flows

									For the periods
			For the Years Ended December 31,						Oct. 20- Dec. 31,			I I	Jan. 1- Oct. 19,
			2002			2001			2000			I I	2000
			(in millions)
Cash Flows from Operating Activities												I
Net Income			$	790		$	607		$	133		I	$	599
Adjustments to reconcile Net Income to Net Cash Flows												I
provided by Operating Activities:												I
	Depreciation and Amortization			522			665			174		I		1,012
	(Gain)/Loss on Forward Share Arrangements			—			—			—		I		(113	)
	Reversal of Provision for Revenue Refunds			—			(15	)		—		I		—
	Provision for Uncollectible Accounts			50			42			16		I		30
	Deferred Income Taxes			118			14			72		I		861
	Merger-Related Costs			—			—			14		I		53
	Early Retirement and Separation Program			—			—			—		I		28
	Midwest Independent System Operator Exit Fees			—			(36	)		—		I		—
	Other Operating Activities			(13	)		(25	)		(69	)	I		(159	)
	Changes in Working Capital:											I
		Accounts Receivable		(72	)		76			(37	)	I		96
		Inventories		(9	)		16			97		I		17
		Accounts Payable, Accrued Expenses & Current Liabilities		135			149			65		I		(1,334	)
		Change in Receivables and Payables to Affiliates, net		461			(149	)		—		I		(10	)
		Other Current Assets		1			2			59		I		(6	)
												I
Net Cash Flows provided by Operating Activities				1,983			1,346			524		I		1,074
												I
Cash Flows from Investing Activities												I
	Investment in Plant, net			(780	)		(869	)		(207	)	I		(1,224	)
	Proceeds from Nuclear Decommissioning Trust Funds			—			—			288		I		1,251
	Investment in Nuclear Decommissioning Trust Funds			—			—			(377	)	I		(1,290	)
	Change in Receivables from Affiliates			14			400			(441	)	I		288
	Other Investments			—			—			(63	)	I		139
	Other Investing Activities			7			11			—		I		9
												I
Net Cash Flows used in Investing Activities				(759	)		(458	)		(800	)	I		(827	)
												I
Cash Flows from Financing Activities												I
	Issuance of Long-Term Debt, net of issuance costs			752			—			—		I		450
	Common Stock Repurchases			—			—			—		I		(153	)
	Retirement of Long-Term Debt			(1,551	)		(542	)		(84	)	I		(755	)
	Change in Short-Term Debt			71			—			—		I		(5	)
	Redemption of Preferred Securities of Subsidiaries			—			—			—		I		(71	)
	Change in Restricted Cash			(24	)		19			50		I		175
	Dividends on Capital Stock			(470	)		(483	)		(95	)	I		(260	)
	Common Stock Forward Repurchases			—			—			—		I		(67	)
	Nuclear Fuel Lease Principal Payments			—			—			—		I		(270	)
	Other Financing Activities			(9	)		—			—		I		—
												I
Net Cash Flow used in Financing Activities				(1,231	)		(1,006	)		(129	)	I		(956	)
												I
Increase (Decrease) in Cash and Cash Equivalents				(7	)		(118	)		(405	)	I		(709	)
Cash and Cash Equivalents at beginning of period				23			141			546		I		1,255
												I
Cash and Cash Equivalents at end of period			$	16		$	23		$	141		I	$	546
												I

See Notes to Consolidated Financial Statements

147

Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets

			December 31,
			2002			2001
			(in millions)
Assets
Current Assets
	Cash and Cash Equivalents		$	16		$	23
	Restricted Cash			65			41
	Accounts Receivable, net
		Customer		782			745
		Other		72			87
	Inventories, at average cost			65			56
Deferred Income Taxes				20			52
	Receivables from Affiliates			15			6
	Other			14			15

		Total Current Assets		1,049			1,025

Property, Plant and Equipment, net				7,744			7,351
Deferred Debits and Other Assets
	Regulatory Assets			447			667
	Investments			54			64
	Goodwill, net			4,916			4,902
	Receivables from Affiliates			1,300			1,314
	Other			320			304

		Total Deferred Debits and Other Assets		7,037			7,251

Total Assets			$	15,830		$	15,627

Liabilities and Shareholders' Equity
Current Liabilities
Notes Payable			$	71		$	—
Long-Term Debt Due Within One Year				698			849
Accounts Payable				201			144
Accrued Expenses				477			374
Payables to Affiliates				416			218
Customer Deposits				81			90
Other				79			122

		Total Current Liabilities		2,023			1,797

Long-Term Debt				5,268			5,850
Deferred Credits and Other Liabilities
	Deferred Income Taxes			1,650			1,671
	Unamortized Investment Tax Credits			51			55
	Pension Obligation			91			151
	Non-Pension Postretirement Benefits Obligation			138			146
	Payables to Affiliates			224			297
	Other			297			248

		Total Deferred Credits and Other Liabilities		2,451			2,568

Commitments and Contingencies
Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding the Company's Subordinated Debt Securities				330			329
Shareholders' Equity
	Common Stock			1,588			2,048
	Preference Stock			7			7
	Other Paid in Capital			4,239			5,057
	Receivable from Parent			(615	)		(937	)
	Retained Earnings			577			257
	Treasury Stock, at cost			—			(1,344	)
	Accumulated Other Comprehensive Income, net			(38	)		(5	)

		Total Shareholders' Equity		5,758			5,083

Total Liabilities and Shareholders' Equity			$	15,830		$	15,627

See Notes to Consolidated Financial Statements

148

Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholders' Equity

	Common Stock			Preferred and Preference Stock			Other Paid-in Capital			Receivable from Parent			Retained Earnings			Accumulated Other Comprehensive Income			Treasury Stock			Total Shareholders' Equity
	(in millions)
Balance, December 31, 1999	$	2,678		$	9		$	2,211		$	—		$	433		$	8		$	(27	)	$	5,312
Net Income		—			—			—			—			599			—			—			599
Preferred and Preference Stock Redemptions		—			(2	)		—			—			—			—			—			(2	)
Capital Stock Expense		—			—			—			—			(1	)		—			—			(1	)
Common Stock Dividends		—			—			—			—			(238	)		—			—			(238	)
Preferred and Preference Stock Dividends		—			—			—			—			(1	)		—			—			(1	)
Common Stock Repurchases		—			—			—			—			—			—			(153	)		(153	)
Stock Forward Repurchase Contract		—			—			—			—			—			—			(993	)		(993	)
Other Comprehensive Income, net of income taxes of $0		—			—			—			—			—			(2	)		—			(2	)

Balance, October 19, 2000		2,678			7			2,211			—			792			6			(1,173	)		4,521
Net Income		—			—			—			—			133			—			—			133
Merger Fair Value Adjustments		—			—			3,177			—			(792	)		(6	)		—			2,379
Common Stock Repurchases		—			—			—			—			—			—			(850	)		(850	)

Balance, December 31, 2000		2,678			7			5,388			—			133			—			(2,023	)		6,183
Net Income		—			—			—			—			607			—			—			607
Receivable from Parent		—			—			1,062			(1,062	)		—			—			—			—
Repayment of Receivable from Parent		—			—			—			125			—			—			—			125
Retirement of Treasury Shares		(630	)		—			(1,393	)		—			—			—			2,023			—
Merger Fair Value Adjustments		—			—			24			—			—			—			—			24
Corporate Restructuring		—			—			(24	)		—			—			—			(1,344	)		(1,368	)
Common Stock Dividends		—			—			—			—			(483	)		—			—			(483	)
Other Comprehensive Income, net of income taxes of $(1)		—			—			—			—			—			(5	)		—			(5	)

Balance, December 31, 2001		2,048			7			5,057			(937	)		257			(5	)		(1,344	)		5,083
Net Income		—			—			—			—			790			—			—			790
Repayment of Receivable from Parent		—			—			—			322			—			—			—			322
Allocation of Tax Benefit from Parent		—			—			28			—			—			—			—			28
Retirement of Treasury Shares		(460	)		—			(884	)		—			—			—			1,344			—
Merger Fair Value Adjustments		—			—			38			—			—			—			—			38
Common Stock Dividends		—			—			—			—			(470	)		—			—			(470	)
Other Comprehensive Income, net of income taxes of $(23)		—			—			—			—			—			(33	)		—			(33	)

Balance, December 31, 2002	$	1,588		$	7		$	4,239		$	(615	)	$	577		$	(38	)	$	—		$	5,758

See Notes to Consolidated Financial Statements

149

Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Comprehensive Income

								For the Periods
		For the Years Ended December 31,						Oct. 20-Dec. 31,			I I	Jan.1-Oct. 19
		2002			2001			2000			I I	2000
		(in millions)
Net Income		$	790		$	607		$	133		I	$	599
Other Comprehensive Income											I
	Cash Flow Hedge Fair Value Adjustment, net of										I
	income taxes of $(21) and $0, respectively	$	(30	)	$	(1	)	$	—		I	$	—
	Foreign Currency Translation Adjustment, net of										I
	income taxes of $0		—			(1	)		—		I		—
	Unrealized Gain (Loss) on Marketable Securities, net										I
	of income taxes of $(1), $(1), $0 and $0, respectively		(3	)		(3	)		—		I		(2	)
	Merger Fair Value Adjustment		—			—			(6	)	I		—
											I
Total Other Comprehensive Income			(33	)		(5	)		(6	)	I		(2	)
											I
Total Comprehensive Income		$	757		$	602		$	127		I	$	597
											I

See Notes to Consolidated Financial Statements

150

Commonwealth Edison Company and Subsidiary Companies
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, unless otherwise noted)

1. Significant Accounting Policies

Description of Business. As a result of the corporate restructuring, effective January 1, 2001 (see Note 2—Corporate Restructuring), Commonwealth Edison Company's (ComEd's) generation and other competitive businesses were separated from its regulated energy delivery business. As a result, the operations of ComEd consist of its retail electricity sales, distribution and transmission businesses to 3.6 million retail customers. ComEd's retail electric service territories are located principally in northern Illinois including metropolitan Chicago, spanning an area of approximately 11,300 square miles.

Basis of Presentation. The consolidated financial statements of ComEd include the accounts of ComEd, Commonwealth Edison Company of Indiana, Inc., Edison Development Canada Inc., Edison Finance Partnership, ComEd Financing I, ComEd Financing II, ComEd Funding LLC (ComEd Funding), and ComEd Transitional Funding Trust (ComEd Funding Trust). All significant intercompany transactions have been eliminated. Although the accounts of ComEd Funding and ComEd Funding Trust, which are Special Purpose Entities (SPEs), are included in the consolidated financial statements, as required by generally accepted accounting principles (GAAP), ComEd Funding and ComEd Funding Trust are separate legal entities from ComEd. The assets of the SPEs are not available to creditors of ComEd and the transitional property held by the SPEs are not assets of ComEd.

Accounting policies for regulated operations are in accordance with those prescribed by the regulatory authorities having jurisdiction, principally the Illinois Commerce Commission (ICC), the Federal Energy Regulatory Commission (FERC) and the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA).

ComEd, a regulated electric utility, is a principal subsidiary of Exelon Corporation (Exelon), which owns 99.9% of ComEd's common stock. ComEd was the principal subsidiary of Unicom Corporation (Unicom) prior to the merger with Exelon. See Note 3—Merger for further discussion of the merger. The merger was accounted for using the purchase method of accounting in accordance with GAAP. The effects of the purchase method are reflected on the financial statements of ComEd as of the merger date. Accordingly, the financial statements presented for the period after the merger reflect a new basis of accounting. ComEd's financial statements for 2000, separated by a bold black line, are presented for periods prior to and subsequent to the merger.

Accounting for the Effects of Regulation. ComEd accounts for its regulated electric operations in accordance with Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," requiring ComEd to record in the financial statements the effects of the rate regulation to which these operations are currently subject. Use of SFAS No. 71 is applicable to the utility operations of ComEd that meet the following criteria: third-party regulation of rates; cost-based rates; and a reasonable assumption that all costs will be recoverable from customers through rates. ComEd believes that it is probable that regulatory assets associated with these operations will be recovered. If a separable portion of ComEd's business no longer meets the provisions of SFAS No. 71, ComEd is required to eliminate the financial statement effects of regulation for that portion.

Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ

151

from those estimates. Areas in which significant estimates have been made include, but are not limited to, the accounting for unbilled revenue, derivatives, goodwill impairment analysis, environmental costs, retirement benefit costs and prior to the corporate restructuring nuclear decommissioning liabilities.

Segment Information. ComEd operates in one segment—energy delivery. Energy delivery consists of the retail electricity distribution and transmission business of ComEd in northern Illinois.

Revenues. Operating revenues are generally recorded as service is rendered or energy is delivered to customers. At the end of each month, ComEd accrues an estimate for the unbilled amount of energy delivered or services provided to its customers. (See Note 7—Accounts Receivable.)

Nuclear Fuel. Prior to the corporate restructuring in which ComEd's nuclear generating stations were transferred to Exelon Generation Company, LLC (Generation) (see Note 2—Corporate Restructuring), the cost of nuclear fuel was capitalized and charged to fuel expense using the unit of production method. Estimated costs of nuclear fuel storage and disposal were charged to expense as the related fuel was consumed.

Stock-Based Compensation. ComEd uses the disclosure-only provisions of SFAS No. 123, "Accounting for Stock-Based Compensation" (SFAS No. 123). The table below shows the effect on net income had ComEd elected to account for its stock-based compensation plans using the fair value method under SFAS No. 123 for the years ended December 31, 2002, 2001 and 2000:

					For the periods
	For the Years Ended December 31,				Oct. 20- Dec. 31,		I I	Jan. 1- Oct. 19,
	2002		2001		2000		I I	2000
	(in millions)
Net income—as reported	$	790	$	607	$	133	I	$	596
Deduct: Total stock-based compensation expense							I
determined under fair value based method for all awards,							I
net of income taxes		13		10		10	I		3
							I
Pro forma net income	$	777	$	597	$	123	I	$	593
							I

Income Taxes. Deferred Federal and state income taxes are provided on all significant temporary differences between the book basis and tax basis of assets and liabilities, transactions that reflect taxable income in a year different from book income and tax carryforwards. Investment tax credits previously used for income tax purposes have been deferred on ComEd's Consolidated Balance Sheets and are recognized in book income over the life of the related property. ComEd and its subsidiaries file a consolidated Federal and state income tax returns with Exelon, and was previously included in Unicom's consolidated income tax returns. Income taxes of the consolidated group are allocated to ComEd based on the separate return method. (See Note 11—Income Taxes)

Gains and Losses on Reacquired Debt. Recoverable gains and losses on reacquired debt related to regulated operations are deferred and amortized to interest expense over the period consistent with rate recovery for ratemaking purposes. In 2000, prior to the corporate restructuring, gains and losses on reacquired debt were recognized in ComEd's Consolidated Statements of Income as incurred (see Note 6—Supplemental Financial Information).

Comprehensive Income. Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to shareholders. Comprehensive income is reflected in the Consolidated Statements of Changes in Shareholders' Equity and the Consolidated Statements of Comprehensive Income.

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Cash and Cash Equivalents. ComEd considers all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents.

Restricted Cash. Restricted cash reflects escrowed cash to be applied to the principal and interest payments on the transitional trust notes.

Marketable Securities. Marketable securities are classified as available-for-sale securities and are reported at fair value, with the unrealized gains and losses, net of tax, reported in other comprehensive income. Prior to the corporate restructuring (see Note 2—Corporate Restructuring), unrealized gains and losses on marketable securities held in the nuclear decommissioning trust funds were reported in accumulated depreciation for operating units and as a reduction of regulatory assets for retired units. At December 31, 2002 and 2001, ComEd had no held-to-maturity or trading securities.

Property, Plant and Equipment. Property, plant and equipment is recorded at cost. ComEd evaluates the carrying value of property, plant and equipment and other long-term assets based upon current and anticipated undiscounted cash flows, and recognizes an impairment when it is probable that such estimated cash flows will be less than the carrying value of the asset. Measurement of the amount of impairment, if any, is based upon the difference between carrying value and fair value. The cost of maintenance, repairs and minor replacements of property are charged to maintenance expense as incurred. Upon retirement, the cost of regulated property plus removal costs less salvage, is charged to accumulated depreciation in accordance with the provisions of SFAS No. 71. For unregulated property, the cost and accumulated depreciation of property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of the gain or loss on disposition (see Note 8—Property, Plant and Equipment).

Depreciation, Amortization and Decommissioning. Depreciation, including a provision for estimated removal costs as authorized by the ICC, is provided over the estimated service lives of property, plant, and equipment on a straight line basis. Annual depreciation provisions for financial reporting purposes, expressed as a percentage of average service life for each asset category are presented below:

Asset Category	2002		2001		2000
Electric—Transmission and Distribution	3.74	%	5.20	%	5.83	%
Electric—Generation	—		—		4.83	%
Other Property and Equipment	7.92	%	5.95	%	7.31	%

Effective July 1, 2002, ComEd has lowered its depreciation rates based on a new depreciation study reflecting its significant construction program in recent years, changes in and development of new technologies, and changes in estimated plant service lives since the last depreciation study. The annualized reduction in depreciation expense, based on December 31, 2001 plant balances, is estimated to be approximately $100 million ($60 million, net of income taxes). As a result of the change, net income for the year ended December 31, 2002 increased approximately $48 million ($29 million, net of income taxes).

Amortization of regulatory assets is provided over the recovery period specified in the related legislation or regulatory agreement. See Note 5—Regulatory Issues regarding the regulatory accounting treatment for the nuclear generating stations transferred to Generation. Goodwill associated with the merger was amortized on a straight line basis over 40 years in 2001 and 2000. Accumulated amortization of goodwill was $149 at December 31, 2001. Effective January 1, 2002, under SFAS No. 142 "Goodwill and Other Intangible Assets"(SFAS 142), goodwill recorded by ComEd is no longer subject to amortization (see the New Accounting Pronouncement section of this note).

ComEd's estimate of the costs for decommissioning nuclear generating stations transferred to Generation is currently included in regulated rates. Prior to the corporate restructuring the amounts

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recovered from customers were deposited in trust accounts and invested for funding of future costs for current and retired plants. ComEd accounted for the current period cost of decommissioning by recording a charge to depreciation expense and a corresponding liability in accumulated depreciation for its operating nuclear units and a reduction to regulatory assets for its retired units. Subsequent to the corporate restructuring, amounts recovered from customers are remitted to Generation.

Capitalized Interest. ComEd uses SFAS No. 34, "Capitalization of Interest Costs," to calculate the costs during construction of debt funds used to finance its non-regulated construction projects. ComEd did not record any capitalized interest in 2002 and 2001, but did record capitalized interest of $5 million in 2000.

Allowance for Funds Used During Construction (AFUDC) is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC of $18 million, $17 million and $19 million in 2002, 2001 and 2000, respectively, was recorded as a charge to Construction Work in Progress and as a non-cash credit to AFUDC which is included in Other Income and Deductions. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.

Capitalized Software Costs. Costs incurred during the application development stage of software projects which are developed or obtained for internal use are capitalized. At December 31, 2002 and 2001, net capitalized software costs totaled $153 million and $104 million, respectively, reflecting $39 million and $17 million in accumulated amortization, respectively. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, not to exceed 10 years. Certain capitalized software is being amortized over 15 years pursuant to regulatory approval. During 2002, 2001 and 2000, ComEd amortized capitalized software costs of $23 million, $14 million and $11 million, respectively.

Derivative Financial Instruments. ComEd accounts for derivative financial instruments pursuant to SFAS No. 133, "Accounting for Derivatives and Hedging Activities" (SFAS 133). Under the provisions of SFAS 133, all derivatives are recognized on the balance sheet at their fair value unless they qualify for a normal purchases and normal sales exception. Changes in the fair value of the derivative financial instrument are recognized in earnings unless specific hedge accounting criteria are met. A derivative financial instrument can be designated as a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge), or a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). Changes in the fair value of a derivative that is highly effective as, and is designated and qualifies as a fair value hedge, along with the gain or loss on the hedged asset or liability that is attributable to the hedged risk, are recorded in earnings. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as a cash flow hedge are recorded in other comprehensive income, until earnings are affected by the variability of cash flows being hedged.

In connection with Exelon's Risk Management Policy, ComEd enters into derivatives to effectively convert fixed rate debt to floating rate debt, manage its exposure to fluctuations in interest rates related to planned future debt issuances prior to their actual issuance, as well as exposure to changes in the fair value of outstanding debt which is planned for early retirement.

Prior to the adoption of SFAS No. 133, ComEd applied hedge accounting only if the derivative reduced the risk of the underlying hedged item and was designated at the inception of the hedge, with respect to the hedged item. ComEd recognized any gains or losses on these derivatives when the underlying physical transaction affected earnings.

New Accounting Pronouncements. In June 2001, the FASB issued SFAS No. 143, "Asset Retirement Obligations" (SFAS No. 143).

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SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. ComEd adopted SFAS No. 143 on January 1, 2003 at which time a retirement obligation of approximately $1 million was recorded related to ComEd's obligation to remove underground storage tanks at the end of their useful lives.

The retirement obligation liability reflects the fair value of the obligation at the balance sheet date. The liability recorded represents an obligation for the future retirement of certain assets and, as a result, accretion expense will be accrued on this liability until such time as the obligation is satisfied. Additionally, the standard requires the accrual of an asset related to the obligation, which will be amortized over the remaining lives of the assets. The net difference between the asset recognized and the liability recorded upon adoption of SFAS No. 143 will be recorded as a regulatory asset.

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. ComEd has adopted the disclosure requirements under FIN No. 45, (see Note 16—Commitments and Contingencies) 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.

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 ComEd's consolidated financial position, results of operations and cash flows, has not been fully determined.

See Note 4—Adoption of New Accounting Pronouncements for discussion of the impact of new accounting pronouncements adopted by ComEd.

Reclassifications. Certain prior year amounts have been reclassified for comparative purposes. These reclassifications had no effect on net income or shareholders' equity.

2. Corporate Restructuring

During January 2001, Exelon undertook a corporate restructuring to separate its generation and other competitive businesses from its regulated energy delivery businesses at ComEd and PECO Energy Company (PECO). As part of the restructuring, the generation-related operations and assets and liabilities of ComEd were transferred to Generation. Additionally, certain operations and assets and liabilities of ComEd were transferred to Exelon Business Services Company (BSC). As a result, effective January 1, 2001, the operations of ComEd consist of its retail electricity distribution and transmission business in northern Illinois.

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The corporate restructuring had the following effect on the Condensed Consolidated Balance Sheets of ComEd:

Decrease in Assets:
Current Assets		$	(397	)
Property, Plant and Equipment, net			(781	)
Investments			(85	)
Other Noncurrent Assets			(2,629	)
Decrease (Increase) in Liabilities:
Current Liabilities			799
Long-Term Debt			—
Deferred Income Taxes			(24	)
Other Noncurrent Liabilities			2,212

	Net Assets Transferred	$	(905	)

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

Treasury Stock Received	$	1,344
Other Paid in Capital		24
Notes Payable—Affiliates		(463	)

Total Consideration	$	905

In connection with the restructuring, ComEd assigned its respective rights and obligations under various purchased power and fuel supply agreements to Generation. Additionally, ComEd entered into a purchased power agreement (PPA) with Generation.

Under the PPA between ComEd and Generation, Generation has agreed to supply all of ComEd's load requirements through 2004. Prices for this energy vary depending upon the time of day and month of delivery. During 2005 and 2006, ComEd's PPA is a partial requirements agreement under which ComEd will purchase all of its required energy and capacity from Generation, up to the available capacity of the nuclear generating plants formerly owned by ComEd and transferred to Generation. Under the terms of the PPA, Generation is responsible for obtaining any required transmission service, 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.

The obligation for decommissioning ComEd's nuclear facilities and the related trust fund assets were transferred to Generation concurrently with the transfer of the generating plants and the related Nuclear Regulatory Commission (NRC) operating licenses as of January 1, 2001. ComEd had historically accounted for the current period's cost of decommissioning by recording a charge to depreciation expense and a corresponding liability in accumulated depreciation for its operating units and a reduction to regulatory assets for retired units (in current year dollars) on a straight-line basis over the NRC operating license life of the plants. As of December 31, 2000, ComEd's cumulative liability of $2.1 billion was recorded as a component of accumulated depreciation. Additionally, a $1.3 billion liability representing the present value of the estimated cost of decommissioning nuclear units previously retired was recorded as a long-term liability. These liabilities, as well as investments in trust fund assets of $2.7 billion to fund the costs of decommissioning, were transferred to Generation.

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Additionally, as part of the corporate restructuring, ComEd's liability to the U.S. Department of Energy (DOE) for payment of its one-time fee for spent nuclear fuel disposal was transferred to Generation. As of December 31, 2000, this liability, including accrued interest, was $810 million. Also, provisions for nuclear insurance were assumed by Generation under terms and conditions commensurate with those previously borne by ComEd.

3. Merger

On October 20, 2000, Exelon became the parent corporation of PECO and ComEd as a result of the completion of the transactions contemplated by an Agreement and Plan of Exchange and Merger, as amended (Merger Agreement), among PECO, Unicom Corporation (Unicom) and Exelon. Pursuant to the Merger Agreement, Unicom merged with and into Exelon (Merger). In the Merger, each share of the outstanding common stock of Unicom was converted into 0.875 shares of common stock of Exelon plus $3.00 in cash. As a result of the Merger, Unicom ceased to exist and its subsidiaries, including ComEd, became subsidiaries of Exelon.

The Merger was accounted for using the purchase method of accounting. Purchase transactions resulting in one entity becoming substantially wholly-owned by the acquiror establish a new basis of accounting in the acquired entity's records for the purchased assets and liabilities. Thus, the purchase price has been allocated to the underlying assets purchased and liabilities assumed based on their estimated fair values at the acquisition date. As a result of the application of the purchase method of accounting, the following fair value adjustments as adjusted to reflect final purchase price allocation, including the elimination of accumulated depreciation, retained earnings and other comprehensive income, were recorded in ComEd's Consolidated Balance Sheets:

	Total
Increase (Decrease) in Assets:
Property, Plant and Equipment, net	$	(4,791	)
Goodwill		5,065
Other Assets		(253	)
(Increase) Decrease in Liabilities and Shareholders' Equity:
Deferred Income Taxes	$	1,753
Unamortized Investment Tax Credits		401
Merger Severance Obligation		(319	)
Pension and Postretirement Benefit Obligations		471
Long-Term Debt and Preferred Securities		116
Other Liabilities		(2	)
Other Paid in Capital		(3,239	)
Retained Earnings		792
Accumulated Other Comprehensive Income		6

Reductions to the carrying value of property, plant and equipment balances primarily reflect the fair value of the nuclear generating assets based on discounted cash flow analyses and independent appraisals. Adjustments to deferred income taxes, long-term debt and preferred securities, and other assets and liabilities were recorded based on the estimate of fair market value. Reductions to unamortized investment tax credits represent the adjustment of nuclear generating asset investment tax credits to fair value. Merger severance obligations relating to ComEd's employee exit costs were recorded in the purchase price allocation. Reductions to pension and postretirement benefit obligations primarily reflect elimination of unrecognized net actuarial gains, prior service costs and transition obligations.

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Goodwill represents the purchase price allocation to ComEd of the cost in excess of net assets acquired in the Merger, which was amortized over a forty year period for 2000 and 2001. Annual amortization of goodwill related to the Merger of $126 million was discontinued upon adoption of SFAS 142.

Goodwill associated with the Merger increased by $262 million in 2001 as a result of the finalization of the purchase price allocation. The adjustment resulted primarily from the after-tax effects of a reduction of the regulatory asset for decommissioning retired nuclear plants, additional employee separation costs and the finalization of other purchase price allocations.

Merger-Related Costs. In association with the Merger, ComEd recorded certain reserves for restructuring costs. The reserves associated with Unicom were recorded as part of the application of purchase accounting and did not affect results of operations, consistent with FASB Emerging Issue Task Force (EITF) Issue 95-3, "Recognition of Liabilities in Connection with a Purchase Business Combination."

Merger costs included in purchase price allocation. The purchase price allocation as of December 31, 2000 included a liability of $307 million for Unicom employee costs and liabilities of approximately $39 million for estimated costs of exiting various business activities of former Unicom that were not compatible with the strategic business direction of Exelon.

During 2001, ComEd finalized plans for consolidation of functions, including negotiation of an agreement with the International Brotherhood of Electrical Workers Local 15 regarding severance benefits to union employees. Also, in January of 2001, ComEd transferred a portion of its employee related liabilities to Generation, Enterprises and BSC as part of the corporate restructuring. During 2002, ComEd reduced its reserve by $9 million due to the elimination of identified positions through normal attrition, which did not require payments under ComEd's merger separation plans, and a determination that certain positions would not be eliminated by the end of 2002 as originally planned due to a change in certain business plans. The reduction in the reserve was recorded as a purchase price adjustment to goodwill. In 2001 and 2002, ComEd recorded adjustments to the purchase price allocation as follows:

			Adjustments
	Original Estimate		Adjustments								Adjusted Liabilities
	Original Estimate		Transfer			2001(a)		2002(a)			Adjusted Liabilities
Employee severance payments	$	128	$	(64	)	$	17	$	(7	)	$	74
Other benefits		21		(13	)		8		(2	)		14

Employee severance payments and other benefits		149		(77	)		25		(9	)		88
Actuarially determined pension and postretirement costs		158		(82	)		10		—			86	(b)

Unicom employee cost—ComEd	$	307	$	(159	)	$	35	$	(9	)	$	174

(a): The increase is a result of the identification in 2001 of additional positions to be eliminated, partially offset by the 2002 elimination of identified positions through normal attrition and changes in certain business plans.
(b): The reduction reflects lower estimated pension and post retirement welfare benefits reflecting revised actuarial estimates.

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The following table provides a reconciliation of ComEd's reserve for employee severance and other benefits associated with the Merger:

Adjusted employee severance and other benefits reserve	$	88
Payments to employees in 2000		(5	)
Payments to employees in 2001		(29	)
Payments to employees in 2002		(41	)

Employee severance and other benefits reserve as of December 31, 2002(1)	$	13

(1): Relates to certain benefits that are being paid over a period of years.

The following table provides a reconciliation of the former Unicom positions that were expected to be eliminated as a result of the Merger:

Estimate at October 20, 2000		1,022
2001 adjustments(a)		206

Total positions		1,228

Employees terminated in 2000		65
Employees terminated in 2001		334
Employees terminated in 2002		513
Normal attrition		211
Business plan changes(b)		105

Total Positions		1,228

(a): The increase is a result of the identification of additional positions to be eliminated in 2001.
(b): The reduction is due to a determination in the third quarter of 2002, that certain positions would not be eliminated by the end of 2002 as originally planned due to a change in certain business plans.

4. Adoption of New Accounting Pronouncements

SFAS No. 142. In 2001, the FASB issued SFAS No. 142. ComEd adopted SFAS No. 142 as of January 1, 2002. SFAS No. 142 establishes new accounting and reporting standards for goodwill and intangible assets. Other than goodwill, ComEd does not have significant other intangible assets recorded on its consolidated balance sheets. Under SFAS No. 142, goodwill is no longer subject to amortization, however, goodwill is subject to an assessment for impairment using a two-step fair value based test, the first step of which must be performed at least annually, or more frequently if events or circumstances indicate that goodwill might be impaired. The first step compares the fair value of a reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step compares the carrying amount of the goodwill to the fair value of the goodwill. If the fair value of goodwill is less than the carrying amount, an impairment loss is reported as a reduction to goodwill and a charge to operating expense, except at the transition date, when the loss is reflected as a cumulative effect of a change in accounting principle.

As of December 31, 2001, ComEd's Consolidated Balance Sheets reflected approximately $4.9 billion of net goodwill related to the October 20, 2000 Merger. The first step of the transitional impairment analysis indicated that ComEd's goodwill was not impaired.

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The changes in the carrying amount of goodwill for the year ended December 31, 2002 are as follows:

Balance as of January 1, 2002	$	4,902
Resolution of certain tax matters		21
Merger severance adjustment		(7	)

Balance as of December 31, 2002	$	4,916

Consistent with SFAS No. 142, the remaining goodwill will be reviewed for impairment on an annual basis, or more frequently if significant events occur that could indicate an impairment exists. Such future review would be consistent with the review conducted related to the implementation of SFAS No. 142 (implementation review), which required estimates of numerous items with varying degrees of uncertainty, such as discount rates, terminal value earnings multiples, future revenue levels and estimated future expenditure levels; load growth and the resolution of future rate proceedings. Significant changes from the assumptions used in the implementation review could possibly result in a future impairment loss. 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 under the earnings provisions of the legislation.

ComEd completed its annual update of its goodwill impairment analysis as of November 1, 2002. The results of the first step test indicated that ComEd's goodwill was not impaired.

The following table sets forth ComEd's net income for the year ended December 31, 2002, 2001, and 2000, respectively, adjusted to exclude 2001 and 2000 amortization expense related to goodwill that is no longer amortized.

	Year Ended December 31,				For the period
	Year Ended December 31,				Oct. 20 - Dec. 31 2000			Jan. 1 - Oct. 19 2000
	2002		2001		Oct. 20 - Dec. 31 2000		I I	Jan. 1 - Oct. 19 2000
Reported net income on Common Stock	$	790	$	607	$	133	I	$	596
Goodwill amortization		—		126		23	I		—
							I
Adjusted net income	$	790	$	733	$	156	I	$	596
							I

SFAS No. 144. In September 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). ComEd adopted SFAS No. 144 on January 1, 2002. SFAS No. 144 established accounting and reporting standards for both the impairment and disposal of long-lived assets. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001 and its provisions are generally applied prospectively. The adoption of this statement had no effect on ComEd's reported financial position, results of operations or cash flows.

SFAS No. 145. In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections" (SFAS No. 145). SFAS No. 145 eliminates SFAS No. 4 "Reporting Gains and Losses from Extinguishment of Debt" (SFAS No. 4) and thus allows for only those gains or losses on the extinguishment of debt that meet the criteria of extraordinary items to be treated as such in the financial statements. SFAS No. 145 also amends Statement of Financial Accounting Standards No. 13, "Accounting for Leases" (SFAS No. 13) to require sale-leaseback accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. The adoption of SFAS No. 145 required a reclassification of the 2000 pre-merger extraordinary item of $4 million net of income taxes, to interest expense and income taxes, otherwise it had no effect on ComEd's reported financial position, results of operations or cash flows.

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SFAS No. 133. SFAS No. 133 applies to all derivative instruments and requires that such instruments be recorded on the balance sheet either as an asset or a liability measured at their fair value through earnings, with special accounting permitted for certain qualifying hedges. On January 1, 2001, ComEd adopted SFAS No. 133. The adoption of SFAS No. 133 had no effect on ComEd's reported financial position, results of operations or cash flows.

SFAS No. 148. In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123" (SFAS No. 148). SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation and requires disclosures in both annual and interim financial statements regarding the method of accounting for stock-based compensation and the effect of the method on financial results. SFAS No. 148 is effective for financial statements for fiscal years ending after December 15, 2002. As of December 31, 2002, ComEd has adopted the additional disclosure requirements of SFAS No. 148 and continues to account for stock-compensation plans under the disclosure only provision of SFAS No. 123.

5. Regulatory Issues

Delivery Service Rates. On June 1, 2001, ComEd filed with the ICC to establish delivery service charges for residential customers in preparation for residential customer choice, which began in May 2002. 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 ComEd's Delivery Services Rate Case. The interim order is subject to an audit of test year (2000) expenditures, including capital plant expenditures, with a final order to be issued in 2003. The order sets delivery rates for residential customers choosing a new retail electric supplier. The new rates became effective May 1, 2002 when residential customers became eligible to choose their supplier of electricity. Traditional bundled rates paid by customers that retain ComEd as their electricity supplier are not affected by this order. Bundled rates will remain frozen through 2006, as a result of the June 6, 2002 amendments to the Illinois Restructuring Act that extended the freeze on bundled rates for an additional two years. Delivery service rates for non-residential customers are not affected by the order.

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 this matter 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 pursuant to SFAS No. 90, "Regulated Enterprises—Accounting for Abandonments and Disallowances of Plant Costs an Amendment of FASB Statement No. 71." ComEd is in negotiations with several parties to resolve the delivery service case.

Customer Choice. As of December 31, 2002, all ComEd's customers were eligible to choose an alternative electric supplier 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 alternative supplier had sought approval from the ICC and no electric utilities have chosen to enter the ComEd residential market for the supply of electricity. As of December 31,

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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 alternative electric supplier 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.

Competitive Service Declarations. On November 14, 2002, the ICC entered an interim order in response to ComEd's request to revise the provider of last resort (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. Approximately 370 of ComEd's largest energy customers would be affected, representing an aggregate of approximately 2,500 megawatts. 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 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. (See Note 19—Subsequent Events)

Rate Reductions and Return on Common Equity Threshold. The Illinois restructuring legislation provided a 15% residential base rate reduction effective August 1, 1998 with an additional 5% residential base rate reduction effective October 1, 2001. ComEd's operating revenues were reduced by approximately $99 million and $24 million in 2002 and 2001, respectively due to the 5% residential rate reduction. Notwithstanding the rate reductions and subject to certain earnings tests, a rate freeze is generally in effect until at least January 1, 2007. 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). Earnings for purposes of ComEd's threshold include ComEd's net income calculated in accordance with 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 2000, 2001 or 2002 and does not currently expect to trigger the earnings sharing provisions in the years 2003 through 2006.

Nuclear Decommissioning Costs. 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

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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.

The $73 million annual recovery of decommissioning costs authorized by the ICC order represents a reduction from the $84 million annual recovery in 2000. Accordingly, in the first quarter of 2001, ComEd reduced its nuclear decommissioning regulatory asset to $372 million, reflecting the expected probable future recoveries from customers. The reduction in the regulatory asset in the amount of $347 million was recorded as an adjustment to the Merger purchase price allocation and resulted in a corresponding increase in goodwill. Effective January 1, 2001, ComEd recorded an obligation to Generation of approximately $440 million representing ComEd's legal requirement to remit funds to Generation for the remaining regulatory asset amount of $372 million upon collection from customers, and for collections from customers prior to the establishment of external decommissioning trust funds in 1989 to be remitted to Generation for deposit into the decommissioning trusts through 2006. At December 31, 2002, the nuclear decommissioning regulatory asset had an unamortized balance of $248 million.

6. Supplemental Financial Information

Supplemental Income Statement Information

	For the Year Ended December 31,				For the period
	For the Year Ended December 31,				Oct. 20 - Dec. 31 2000				Jan. 1 - Oct. 19 2000
	2002		2001		Oct. 20 - Dec. 31 2000			I I	Jan. 1 - Oct. 19 2000
Taxes Other Than Income								I
Utility(a)	$	205	$	203	$	52		I	$	224
Real Estate		20		33		22		I		101
Payroll		28		28		12		I		57
Other		34		32		(3	)	I		43
								I
Total	$	287	$	296	$	83		I	$	425
								I

(a): Represents municipal and state utility taxes which are included in Revenues and Taxes Other Than Income.

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The decrease in taxes other than income from 2000 was primarily due to the corporate restructuring in which ComEd's nuclear generating stations were transferred to Generation (see Note 2—Corporate Restructuring) and a change in presentation of certain revenue taxes which did not affect income.

	For the Year Ended December 31,					For the period
	For the Year Ended December 31,					Oct. 20 - Dec. 31 2000				Jan. 1 - Oct. 19 2000
	2002			2001		Oct. 20 - Dec. 31 2000			I I	Jan. 1 - Oct. 19 2000
Other, Net									I
Investment Income	$	11		$	18	$	9		I	$	39
Gain on forward share purchases		—			—		—		I		113
Gain (loss) on disposition of assets, net		—			—		—		I		(31	)
AFUDC, equity and borrowed		18			17		—		I		19
Reserve for potential plant disallowance		(12	)		—		—		I		—
Other income (expense)		(3	)		—		(7	)	I		(13	)
									I
Total	$	14		$	35	$	2		I	$	127
									I

Supplemental Cash Flow Information

		For the Year Ended December 31,					For the period
		For the Year Ended December 31,					Oct. 20 - Dec. 31 2000			Jan. 1 - Oct. 19 2000
		2002		2001			Oct. 20 - Dec. 31 2000		I I	Jan. 1 - Oct. 19 2000
Cash paid during the year:									I
	Interest (net of amount capitalized)	$	417	$	451		$	88	I	$	418
	Income taxes (net of refunds)		264		300			11	I		1,190
Non-cash investing and financing:									I
	Common stock repurchase	$	—	$	—		$	850	I	$	—
	Settlement of forward share								I
	repurchase arrangement		—		—			—	I		993
	Deferred tax on fossil plant sale		—		—			—	I		1,094
	Net assets transferred as a result of the								I
	corporate restructuring, net of note payable		—		1,368			—	I		—
	Contribution of receivable from parent		—		1,062			—	I		—
	Resolution of certain tax matters and merger								I
	severance adjustments		14		—			—	I		—
	Purchase accounting estimate Adjustments		—		(85	)		—	I		—
	Regulatory asset fair value Adjustments		—		347			—	I		—
	Retirement of treasury shares		1,344		2,023			—	I		—
Depreciation and amortization:									I
	Property, plant and equipment	$	358	$	369		$	82	I	$	543
	Nuclear fuel		—		—			44	I		144
	Regulatory assets		164		170			9	I		257
	Decommissioning		—		—			16	I		68
	Goodwill		—		126			23	I		—
									I
Total depreciation and amortization		$	522	$	665		$	174	I	$	1,012
									I

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Supplemental Balance Sheet Information

	December 31,
	2002			2001
Regulatory Assets
Nuclear decommissioning costs for retired plants	$	248		$	310
Recoverable transition costs		175			277
Reacquired debt costs and interest rate swap settlements		84			54
Recoverable deferred income taxes (see Note 11—Income Taxes)		(68	)		26
Other		8			—

Total	$	447		$	667

Nuclear decommissioning costs for retired plants—Recovery is provided for through ComEd's current regulated rates and is expected to be fully recovered by the end of 2006.

Recoverable transition costs—Recovery is provided for in regulated rates pursuant to the Illinois Restructuring Act and is expected to be fully recovered by the end of 2006.

Reacquired debt costs and interest rate swap settlements—Recoverable gains and losses on reacquired debt costs and interest rate swap settlements are deferred and amortized over the rate-recovery period, which is over the life of the new debt issued to finance the debt redemption.

The regulatory assets related to nuclear decommissioning costs and deferred income taxes did not require a cash outlay of investor supplied funds; consequently, these costs are not earning a rate of return. Recovery of the regulatory assets for loss on reacquired debt and interest rate swap settlements and recoverable transition costs is provided for through regulated revenue sources that are based on pre-open access cost of service. Therefore they are earning a rate of return.

The regulatory assets for reacquired debt costs, interest rate swap settlements and deferred income taxes relate to ComEd's transmission and distribution business which is subject to cost-based rate regulation. The regulatory assets for nuclear decommissioning costs for retired plants and recoverable transition costs represent generation-related costs which are recoverable through regulated cash flows. ComEd's regulated cash flows include revenues for bundled service (delivery plus generation services) and, for those customers that have elected to obtain energy services from an alternative supplier, a cost-based delivery charge and a competitive transition charge (CTC). ComEd's revenues for bundled service are based on pre-open access cost of service based rates, reduced by a 20% rate reduction for residential customers. For customers electing unbundled service, the CTC is calculated based upon a "lost revenues" approach whereby ComEd is generally made whole for the difference between revenues it would have received under cost-based rates and revenues expected to be received from market-based prices, except for an amount calculated by applying a mitigation factor. ComEd has performed projections to determine if the revenue streams provided through these regulated cash flows are sufficient to provide for recovery of its regulatory assets during the rate-freeze period and concluded that cash flows were sufficient to provide recovery of its operating costs and net assets, including recovery of regulatory assets and a reasonable regulated rate of return on its net assets. Further, the Illinois Restructuring Act provides for an earnings floor and ceiling, such that if ComEd's earned rate

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of return falls below a specified floor, ComEd may request a rate increase and, conversely, if its earnings exceed an established threshold, so-called excess earnings must be shared with ratepayers.

	December 31,
	2002		2001
Accrued Expenses
Accrued Expenses	$	60	$	63
Taxes Accrued		234		146
Interest Accrued		183		165

Total	$	477	$	374

7. Accounts Receivable

Accounts Receivable—Customer at December 31, 2002 and 2001 included unbilled operating revenues of $250 million and $261 million, respectively. The allowance for uncollectible accounts at December 31, 2002 and 2001 was $23 million and $49 million, respectively.

Effective April 1, 2002, ComEd changed its accounting estimate related to the allowance for uncollectible accounts. This change was based on an independently prepared evaluation of the risk profile of ComEd's customer accounts receivable. As a result of the new evaluation, the allowance for uncollectible accounts reserve was reduced by $11 million in 2002.

8. Property, Plant and Equipment

A summary of property, plant and equipment by classification as of December 31, 2002 and 2001 is as follows:

			2002		2001
Electric—Transmission & Distribution			$	6,776	$	6,098
Construction Work in Progress				373		547
Other Property, Plant and Equipment				1,082		942

	Total Property, Plant and Equipment			8,231		7,587
		Less Accumulated Depreciation		487		236

Property, Plant and Equipment, net			$	7,744	$	7,351

9. Notes Payable

	2002			2001	2000
Average borrowings	$	14		—	$	214
Average interest rates, computed on daily basis		1.75	%	—		6.56	%
Maximum borrowings outstanding	$	146		—	$	494
Average interest rates, at December 31		1.69	%	—		—

ComEd, along with Exelon, PECO and Generation, entered into a $1.5 billion 364-day unsecured revolving credit facility on November 22, 2002 with a group of banks. Under the credit facility, each borrower may borrow up to a designated sublimit amount on a revolving credit basis through November 20, 2003. This credit facility 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. At December 31, 2002, ComEd's sublimit was $200 million. This credit facility is used principally to support ComEd's commercial paper program. At December 31, 2002, ComEd had $123 million of

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commercial paper outstanding of which $52 million has been classified as long-term debt under the provisions of SFAS No. 6, "Classification of Short-Term Obligations Expected to be Refinanced" (SFAS 6) (see Note 19—Subsequent Events). Interest rates on the advances under the credit facility are based on the London Interbank Offering Rate as of the date of the advance.

10. Long-Term Debt

		December 31, 2002		December 31,
		Rates	Maturity Date	2002			2001
Securitized Long-Term Debt
ComEd Transitional Trust Notes
	Series 1998-A:	5.39%-5.74%	2003-2008	$	2,040		$	2,380
Other Long-Term Debt
First and Refunding Mortgage Bonds(a)(b):
	Fixed rates	4.40%-9.875%	2003-2023		2,612			2,916
	Floating rates	1.33%	2013		100			—
Notes payable
	Fixed Rates	6.40%-9.20%	2004-2018		816			1,116
	Floating rates	2.03%	2003		250			250
Pollution control bonds:
	Fixed rates	5.875%	2007		42			44
	Floating rates	1.05%-1.50%	2009-2014		92			92
Sinking fund debentures		3.125%-4.75%	2004-2011		20			23
Commercial paper(c)		1.69%	2003		52			—

Total Long-Term Debt(d)					6,024			6,821
	Unamortized debt discount and premium, net				(99	)		(122	)
	Fair value hedge carrying value adjustment				41			—
	Due within one year				(698	)		(849	)

Long-Term Debt				$	5,268		$	5,850

(a): Utility plant of ComEd is subject to the liens of its mortgage indenture.
(b): Includes pollution control bonds collateralized by first mortgage bonds issued under ComEd's mortgage indenture.
(c): Classified as long-term at December 31, 2002 since it was refinanced with long-term debt in January 2003.
(d): Long-term debt maturities in the period 2003 through 2007 and thereafter are as follows:

2003	$	750
2004		577
2005		806
2006		769
2007		526
Thereafter		2,596

Total	$	6,024

2003 maturities include $52 million of commercial paper classified as long-term debt (see Note 19—Subsequent Events).

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In 2002, ComEd issued $700 million of long-term debt primarily consisting of the issuance of $600 million of 6.15% First Mortgage Bonds, Series 98, due March 15, 2012, and the issuance of $100 million of Illinois Development Finance Authority floating-rate Pollution Control Revenue Refunding Bonds, Series 2002 due April 15, 2013. In 2002, ComEd redeemed or paid at maturity $1,551 million of long-term debt primarily consisting of the redemption of $100 million of 7.25% Illinois Development Finance Authority Pollution Control Revenue Refunding Bonds, Series 1991 due June 1, 2011, the redemption of $200 million of 8.625% First Mortgage Bonds, Series 81, due February 1, 2022, the redemption of $200 million of 8.5% First Mortgage Bonds, Series 84 due July 15, 2022, the payment at maturity of $200 million of 7.375% First Mortgage Bonds, Series 85, due September 15, 2002, the redemption of $200 million of 8.375% First Mortgage Bonds, Series 86, due September 15, 2022, the payment at maturity of $200 million of variable rate senior notes due September 30, 2002, the payment at maturity of $100 million of 9.17% medium-term notes due October 15, 2002, and the retirement of $340 million in transitional trust notes.

In 2002, ComEd exchanged $600 million of 6.15% First Mortgage Bonds, Series 98, due March 15, 2012, for bonds which are registered under the Securities Act. The exchange bonds are identical to the outstanding bonds except for the elimination of certain transfer restrictions and registration rights pertaining to the outstanding bonds. ComEd did not receive any cash proceeds from issuance of the exchange bonds.

In 2002 and 2001, ComEd entered into forward-starting interest rate swaps with an aggregate notional amount of $830 million and $250 million, respectively, to manage interest rate exposure associated with anticipated debt issuance. In connection with the 2002 issuance of the $600 million of 6.15% First Mortgage Bonds, forward-starting interest rate swaps with an aggregate notional amount of $450 million were settled with net proceeds to counterparties of $10 million that has been deferred in regulatory assets and is being amortized over the life of the First Mortgage Bonds as an increase to interest expense.

In 2002 and 2001, ComEd entered into interest rate swap agreements with a notional amount $250 million and $235 million, respectively, to effectively convert fixed rate debt to floating rate debt.

In 2001, ComEd redeemed $196 million of 9.875% First Mortgage Bonds, Series 75, due June 15, 2020 and retired $340 million in transitional trust notes.

Prepayment premiums of $24 million and net unamortized premiums, discounts and debt issuance expenses of $3 million, and prepayment premiums of $39 million, offset by unamortized issuance premiums of $17 million, associated with the early retirement of debt in 2002 and 2001, respectively, have been deferred in regulatory assets and will be amortized to interest expense over the life of the related new debt issuance consistent with regulatory recovery. In 2000, ComEd incurred charges aggregating $6 million consisting of prepayment premiums and the write-offs of unamortized deferred financing costs associated with the early retirement of debt.

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11. Income Taxes

Income tax expense (benefit) is comprised of the following components:

		For the Year Ended December 31,						For the period
		For the Year Ended December 31,						Oct. 20 - Dec. 31 2000			Jan. 1 - Oct. 19 2000
		2002			2001			Oct. 20 - Dec. 31 2000		I I	Jan. 1 - Oct. 19 2000
Included in operations:										I
Federal										I
	Current	$	308		$	400		$	24	I	$	(522	)
	Deferred		110			16			57	I		729
	Investment tax credit, net		(4	)		(4	)		—	I		(25	)
State										I
	Current		80			92			7	I		(112	)
	Deferred		12			2			15	I		157
										I
		$	506		$	506		$	103	I	$	227
										I

The effective tax rate varies from the U.S. Federal statutory rate principally due to the following:

		For the Year Ended December 31,				For the period
		For the Year Ended December 31,				Oct. 20 - Dec. 31 2000			Jan. 1 - Oct. 19 2000
		2002		2001		Oct. 20 - Dec. 31 2000		I I	Jan. 1 - Oct. 19 2000
U.S. Federal statutory rate		35.0	%	35.0	%	35.0	%	I	35.0	%
Increase (decrease) due to:								I
	Plant basis differences	(1.3	)	0.3		(1.7	)	I	(3.7	)
	State income taxes, net of							I
	Federal income tax benefit	4.6		5.5		5.9		I	3.6
	Amortization of goodwill	—		4.0		3.4		I	—
	Amortization of investment tax credit	(0.3	)	(0.4	)	—		I	(2.3	)
	Amortization of regulatory asset	1.2		1.4		—		I	—
	Unrealized loss (gain) on forward share							I
	repurchase arrangement	—		—		—		I	(4.8	)
	Other, net	(0.2	)	(0.3	)	1.0		I	(0.3	)
								I
		39.0	%	45.5	%	43.6	%	I	27.5	%
								I

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The tax effect of temporary differences giving rise to significant portions of ComEd's deferred tax assets and liabilities are presented below:

		December 31,
		2002			2001
Deferred tax liabilities:
	Plant basis difference	$	963		$	895
	Deferred investment tax credits		51			55
	Deferred debt refinancing costs		67			13
	Deferred gain on sale of plants		860			872

Total deferred tax liabilities			1,941			1,835

Deferred tax assets:
	Deferred pension and postretirement obligations		(104	)		(119	)
	Other, net		(156	)		(42	)

Total deferred tax assets			(260	)		(161	)

Deferred income taxes (net) on the balance sheet		$	1,681		$	1,674

In accordance with regulatory treatment of certain temporary differences, ComEd has recorded a regulatory asset/(liability) for recoverable deferred income taxes, pursuant to SFAS No. 109, "Accounting for Income Taxes," of $(68) million and $26 million at December 31, 2002 and 2001, respectively. These recoverable deferred income taxes include the deferred tax effects associated principally with excess deferred taxes and the amortization of investment tax credits accounted for in accordance with the ratemaking policies of the ICC, as well as the revenue impacts thereon, and assume continued recovery of these costs in future rates.

ComEd has taken certain tax positions, which have been disclosed to the Internal Revenue Service (IRS), to defer the tax gain on the 1999 sale of its fossil generating assets. As of December 31, 2002, a deferred tax liability of approximately $860 million related to the fossil plant sale is reflected on ComEd's consolidated balance sheets. Changes in IRS interpretations of existing primary tax authority or challenges to ComEd's positions could have the impact of accelerating future income tax payments and increasing interest expense related to the deferred tax gain that becomes current. ComEd's management believes an adequate reserve for interest has been established in the event that such positions are not sustained. The Federal tax returns covering the period of the 1999 sale are anticipated to be under IRS audit beginning in 2003. Final resolution of this matter is not anticipated for several years.

Certain ComEd tax returns are under review at the audit or appeals level of the IRS and certain state authorities. These reviews by the governmental taxing authorities are not expected to have an adverse impact on the financial condition or result of operations at ComEd.

12. Retirement Benefits

ComEd has adopted defined benefit pension plans and postretirement welfare benefit plans sponsored by Exelon. In 2001, ComEd's former plans were consolidated into the Exelon plans. Essentially all ComEd employees are eligible to participate in these plans. Benefits under these pension plans generally reflect each employee's compensation, years of service, and age at retirement.

The Pension Obligation and Non-Pension Postretirement Obligation on the ComEd Consolidated Balance Sheets reflect ComEd's obligations to the plan sponsor, Exelon. Employee-related assets and liabilities, including both pension and SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other than Pensions," postretirement welfare liabilities, were allocated by Exelon to its

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subsidiaries based on the number of active employees as of January 1, 2001 as part of Exelon's corporate restructuring. Exelon allocates the components of pension expense to the participating employers based upon several factors, including the percentage of active employees in each participating unit.

See Note 15—Retirement Benefits of the Notes to Exelon's Consolidated Financial Statements for pension and other postretirement benefits information for the Exelon plans.

Approximately $15 million and $17 million were included in operating and maintenance expense in 2002 and 2001, respectively, for ComEd's allocated portion of Exelon's pension and postretirement benefit expense. ComEd contributed $82 million to the Exelon-sponsored plans in 2002 and did not make any pension contributions in 2001. In 2000, ComEd recorded a net pension benefit of $29 million and a net postretirement benefit cost of $38 million.

Exelon's costs of providing pension and postretirement benefits are dependent upon a number of factors, such as the rates of return on pension plan assets, discount rate, and the rate of increase in health care costs. The market value of plan assets has been affected by sharp declines in the equity market since the third quarter of 2000. As a result, at December 31, 2002, Exelon was required to recognize an additional minimum liability as prescribed by SFAS No. 87, "Employer's Accounting for Pensions." The liability was recorded as a reduction to common 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 obligations. Based upon the market value of plan assets at December 31, 2002, the amount of the reduction to common equity (net of income taxes) is $1.0 billion. The recording of this reduction, at the Exelon holding company level, did not affect net income or cash flow in 2002 or compliance with debt covenants.

ComEd participates in a 401(k) savings plan sponsored by Exelon. The plan allows employees to contribute a portion of their pretax income in accordance with specified guidelines. ComEd matches a percentage of the employee contribution up to certain limits. The cost of ComEd's matching contribution to the savings plan totaled $19 million, $20 million, and $31 million in 2002, 2001 and 2000, respectively.

13. Preferred Securities

Preferred and Preference Stock. At December 31, 2002 and 2001, there were 6,810,451 authorized shares of preference stock and 850,000 authorized shares of prior preferred stock.

	December 31,
	Shares Outstanding			Dollar Amount
	2002	2001	2000	2002		2001		2000
Without mandatory redemption
Preference stock, non-cumulative, without par value	1,120	1,120	1,120	$	7	$	7	$	7

Total preferred and preference stock	1,120	1,120	1,120	$	7	$	7	$	7

During 2000, 56,291 shares of preferred and preference stock were redeemed.

Shares of preference stock have full voting rights, including the right to cumulate votes in the election of directors.

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Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely the Company's Subordinated Debt Securities. At December 31, 2002 and 2001, subsidiary trusts of ComEd had outstanding the following securities:

							December 31,
							Trust Receipts Outstanding		Dollar Amount
Series		Mandatory Redemption Date	Distribution Rate		Liquidation Value		Trust Receipts Outstanding		Dollar Amount
Series		Mandatory Redemption Date	Distribution Rate		Liquidation Value		2002	2001	2002			2001
ComEd Financing I		2035	8.48	%	$	25	8,000,000	8,000,000	$	200		$	200
ComEd Financing II		2027	8.50	%		1,000	150,000	150,000		150			150
Unamortized Discount										(20	)		(21	)

	Total						8,150,000	8,150,000	$	330		$	329

ComEd Financing I and ComEd Financing II are wholly-owned subsidiary trusts of ComEd. The sole assets of each ComEd trust are subordinated deferrable interest debt securities issued by ComEd bearing interest rates equivalent to the distribution rate of the related trust security.

The interest expense on the deferrable interest debt securities is included in Distributions on Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely the Company's Subordinated Debt Securities in ComEd's Consolidated Statements of Income and is deductible for income tax purposes.

The preferred securities issued by each of ComEd Financing I and II have no voting privileges, except (i) for the right to approve a merger, consolidation or other transaction involving the applicable trust that would result in certain United States Federal income tax consequences to that trust, (ii) with respect to certain amendments to the applicable trust agreement, (iii) for certain voting privileges that arise upon an event of default under the applicable trust agreement or (iv) with respect to certain amendments to the related ComEd guarantee agreement. See Note 19—Subsequent Events.

14. Common Stock

At December 31, 2002 and 2001, common stock with a $12.50 par value consisted of 250,000,000 and 250,000,000 shares authorized and 127,016,409 and 127,016,363 shares outstanding, respectively.

During 2002, ComEd canceled 36.8 million of its common shares totaling $1,344 million. During 2001, ComEd canceled 50.4 million of its common shares totaling $2,023 million.

At December 31, 2002 and 2001, 76,305 and 76,467, respectively, of ComEd common stock purchase warrants were outstanding. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants. At December 31, 2002, 25,435 shares of common stock were reserved for the conversion of warrants.

Forward Purchase Agreements. In January 2000, ComEd physically settled the forward share repurchase arrangements it had with Unicom for the repurchase of 26.3 million ComEd common shares. Prior to settlement, the repurchase arrangements were recorded as a receivable on ComEd's Consolidated Balance Sheets based on the aggregate market value of the shares under the arrangements. In 1999, net unrealized losses of $44 million (after-tax) were recorded related to the arrangements. The settlement of the arrangements in January 2000 resulted in a gain of $113 million (after-tax), which was recorded in the first quarter of 2000. The settlement of the arrangements resulted in a reduction in ComEd's outstanding common shares and common stock equity, effective January 2000.

Stock Repurchases. During the first quarter of 2000, ComEd repurchased four million of its common shares from Unicom for $153 million using proceeds from the 1998 issuance of transitional

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trust notes. In the fourth quarter of 2000, ComEd repurchased 19.9 million of its common shares from Unicom in exchange for an $850 million note receivable ComEd held from Unicom Investment.

As part of the corporate restructuring, ComEd received 36.8 million of its common shares from Exelon totaling $1,344 million in exchange for the net assets transferred to Generation and notes payable received from Generation. These shares were retired during 2002.

Shares Outstanding. The following table details ComEd's common stock and treasury stock:

	Common Shares		Treasury Shares		Total
	(in thousands)
Balance, December 31, 1999	214,238		264		213,974
Conversion of $1.425 Preferred Stock	4		—		4
Common Stock Repurchases	—		3,964		(3,964	)
Stock Forward Repurchase Contract	—		26,268		(26,268	)

Balance, October 19, 2000	214,242		30,496		183,746
Common Stock Repurchases	—		19,941		(19,941	)

Balance, December 31, 2000	214,242		50,437		163,805
Retirement of Treasury Shares	(50,437	)	(50,437	)	0
Restructuring (see Note 2—Corporate Restructuring)	—		36,789		(36,789	)

Balance, December 31, 2001	163,805		36,789		127,016
Retirement of Treasury Shares	(36,789	)	(36,789	)	0

Balance, December 31, 2002	127,016		—		127,016

Fund Transfer Restrictions. Under PUHCA, ComEd can pay dividends only 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. At December 31, 2002, ComEd had retained earnings of $577 million.

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

15. Fair Value of Financial Assets and Liabilities

The carrying amounts and fair values of ComEd's financial instruments as of December 31, 2002 and 2001 were as follows:

		2002						2001
		Carrying Amount			Fair Value			Carrying Amount			Fair Value
Non-derivatives:
Liabilities
	Long-term debt (including amounts due within one year)	$	5,925		$	6,630		$	6,699		$	7,088
Company-Obligated Mandatorily Redeemable Preferred Securities		$	330		$	459		$	329		$	394
Derivatives:
Fixed to floating interest rate swaps		$	41		$	41		$	—		$	—
Forward interest rate swaps		$	(52	)	$	(52	)	$	(1	)	$	(1	)

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As of December 31, 2002 and 2001, ComEd's carrying amounts of cash and cash equivalents and accounts receivable are representative of fair value because of the short-term nature of these instruments. Fair values of the long-term debt and Company-Obligated Mandatorily Redeemable Preferred Securities are estimated based on quoted market prices for the same or similar issues. The fair value of ComEd's interest rate swaps is determined using quoted exchange prices, external dealer prices, or internal valuation models which utilize assumptions of future energy prices and available market pricing curves.

Financial instruments that potentially subject ComEd to concentrations of credit risk consist principally of cash equivalents and customer accounts receivable. ComEd places its cash equivalents with high-credit quality financial institutions. Generally, such investments are in excess of the Federal Deposit Insurance Corporation limits. Concentrations of credit risk with respect to customer accounts receivable are limited due to ComEd's large number of customers and their dispersion across many industries.

ComEd had entered into forward-starting interest rate swaps to manage interest rate exposure. These swaps had been designated as cash-flow hedges under SFAS 133, and as such, as long as the hedge remained effective, and the underlying transaction remained probable, changes in the fair value of these swaps were recorded in accumulated other comprehensive income (loss). In 2002, ComEd paid $10 million to counterparties to settle forward-starting interest rate swaps, designated as cash flow hedges, with an aggregate notional amount of $450 million. The amounts ComEd paid to settle the cash flow hedges were recorded in regulatory assets and will be amortized over the life of the issued debt. At December 31, 2002, ComEd had forward-starting interest rate swaps designated as cash flow hedges with an aggregate notional amount of $630 million.

ComEd has also entered into interest rate swaps to effectively convert $485 million in fixed-rate debt to a floating rate debt. These swaps have been designated as a fair-value hedges, as defined in SFAS No. 133 and as such, changes in the fair value of the swaps will be recorded in earnings. However, as long as the hedge remains effective and the underlying transaction remains probable, changes in the fair value of the swaps will be offset by changes in the fair value of the hedged liabilities. Any change in the fair value of the hedge as a result of ineffectiveness would be recorded immediately in earnings.

The notional amount of derivatives do not represent amounts that are exchanged by the parties and, thus, are not a measure of ComEd's exposure. The amounts exchanged are calculated on the basis of the notional or contract amounts, as well as on the other terms of the derivatives, which relate to interest rates and the volatility of these rates.

ComEd would be exposed to credit-related losses in the event of non-performance by the counterparties that issued the derivative instruments. The credit exposure of derivative contracts is represented by the fair value of contracts at the reporting date. ComEd's interest rate swaps are documented under master agreements. Among other things, these agreements provide for a maximum credit exposure for both parties. Payments are required by the appropriate party when the maximum limit is reached.

The initial adoption of SFAS No.133, as amended, on January 1, 2001 had no financial statement impact on ComEd. SFAS No. 133 must be applied to all derivative instruments and requires that such instruments be recorded in the balance sheet either as an asset or a liability measured at their fair value through earnings, with special accounting permitted for certain qualifying hedges. Additionally, during 2002, no amounts were reclassified from accumulated other comprehensive income into earnings as a result of forecasted financing transactions no longer being probable.

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16. Commitments and Contingencies

Commercial Commitments. 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
			Expiration within						After 5 Years
	Total		1 Year		2-3 Years		4-5 Years		After 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, 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.

Capital Commitments. ComEd estimates that it will spend approximately $720 million for capital expenditures in 2003.

Energy Commitments. In connection with the corporate restructuring (see Note 2—Corporate Restructuring), ComEd assigned its respective rights and obligations under various purchased power and fuel supply agreements to Generation. Additionally, ComEd entered into a PPA with Generation.

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sources in 2005 and 2006, and subsequent to 2006, will obtain all of its supply from market sources, which could include Generation.

Environmental Issues. ComEd's operations have in the past and may in the future require substantial capital expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, ComEd is generally liable for the costs of remediating environmental contamination of property now or formerly owned by ComEd and of property contaminated by hazardous substances generated by ComEd. ComEd owns a number of real estate parcels, including parcels on which its operations or the operations of others may have resulted in contamination by substances which are considered hazardous under environmental laws. ComEd has identified 43 sites where former manufactured gas plant (MGP) activities have or may have resulted in actual site contamination. ComEd is currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.

As of December 31, 2002 and 2001, ComEd had accrued $101 million and $105 million, respectively, for environmental investigation and remediation costs, including $97 million and $100 million, respectively (reflecting discount rates of 5.0% and 5.5%, respectively) for investigation and remediation at its 43 MGP sites, that currently can be reasonably estimated. Such estimates, reflecting the effects of a 2.5% and 3.0% inflation rate before the effects of discounting were $138 million and $154 million at December 31, 2002 and 2001, respectively. ComEd anticipates that payments related to the discounted environmental investigation and remediation costs, recorded on an undiscounted basis of $76 million, will be incurred for the five year period through 2007. ComEd cannot reasonably estimate whether it will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by ComEd, environmental agencies or others, or whether such costs will be recoverable from third parties.

Leases. Minimum future operating lease payments, including lease payments for real estate and vehicles, as of December 31, 2002 were:

2003	$	22
2004		21
2005		17
2006		16
2007		16
Remaining years		43

Total minimum future lease payments	$	135

Rental expense under operating leases totaled $26 million, $23 million, and $30 million in 2002, 2001 and 2000, respectively.

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Litigation.

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. On June 29, 2001, FERC denied the customers' requests for rehearing of the order granting rehearing. As a result of the FERC ruling, in 2001 ComEd reversed a reserve for revenue refunds of $15 million. 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.

General. ComEd is involved in various other litigation matters. The ultimate outcome of such matters, while uncertain, is not expected to have a material adverse effect on its respective financial condition or results of operations.

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17. Related-Party Transactions

ComEd's financial statements reflect related-party transactions as reflected in the tables below.

		For the Year Ended December 31,
		2002		2001		2000
Operating Revenues from Affiliates
	Generation(1)	$	51	$	39	$	—
	Enterprises(1)		12		42		90
Purchased Power from Affiliate
	PPA with Generation(2)		2,559		2,656		—
Operations & Maintenance from Affiliates
	BSC(3)		124		114		—
	Enterprises(4,5)		12		21		—
Interest Income from Affiliates
	UII(6)		30		61		176
	PECO(7)		—		8		—
	Generation(8)		—		9
	Other		1		1		3
Interest Expense from Affiliate
	Generation(2,9)		4		10
Capitalized costs
	BSC(3)		9		23
	Enterprises(5)		21		26
Cash Dividends Paid to Parent			470		483		355

		December 31,
		2002		2001
Receivables from Affiliates
	UII(6)	$	15	$	—
	BSC(3,8)		—		6
Notes Receivable from Affiliates
	UII(6)		1,284		1,297
	Other		16		17
Payables to Affiliates
	Generation Decommissioning (10)		59		59
	Generation(1,2,8)		339		136
	BSC(3,8)		18		—
	Exelon Corporate(11)		—		13
	Other		—		10
Deferred Credits and Other Liabilities
	Generation Decommissioning obligation(10)		218		291
	Other		6		6
Shareholders' Equity—Receivable from Parent(12)			615		937

(1): ComEd provides electric, transmission, and other ancillary services to Generation and Enterprises.
(2): Effective January 1, 2001, ComEd entered into a PPA with Generation. See Note 16—Commitments and Contingencies for further information regarding the PPA. The Generation payable primarily consists of services related to the PPA.

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(3): ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial and information technology services. A portion of such services, provided at cost including applicable overhead, is capitalized.
(4): ComEd has contracted with Exelon Services to provide energy conservation services to ComEd customers.
(5): ComEd receives substation and transmission engineering and construction services under contracts with InfraSource. A portion of such services is capitalized.
(6): ComEd has a note and interest receivable from Unicom Investments Inc. (UII) relating to the December 1999 fossil plant sale.
(7): At December 31, 2000, ComEd had a $400 million receivable from PECO, which was repaid in the second quarter of 2001.
(8): In order to benefit from economies of scale, ComEd processes certain invoice payments on behalf of Generation and BSC. During 2001, ComEd earned interest from Generation relating to these invoice payments.
(9): In consideration for the net assets transferred as part of the corporate restructuring effective January 1, 2001, ComEd had a note payable to affiliates of $463 million. This note payable was repaid during 2001.
(10): ComEd had a short-term and long-term payable to Generation, primarily representing ComEd's legal requirements to remit collections of nuclear decommissioning costs from customers to Generation.
(11): ComEd pays Exelon for a variety of corporate expenses including allocations under a tax sharing agreement and stock options.
(12): ComEd has a non-interest bearing receivable from Exelon related to Exelon's agreement to fund future income tax payments resulting from the collection by ComEd of instrument funding changes. The receivable is expected to be settled over the years 2003 through 2008.

18. Quarterly Data (Unaudited)

The data shown below include all adjustments which ComEd considers necessary for a fair presentation of such amounts:

	Operating Revenues				Operating Income				Net Income
Quarter ended	Operating Revenues				Operating Income				Net Income
Quarter ended	2002		2001		2002		2001		2002		2001
March 31	$	1,315	$	1,446	$	332	$	380	$	129	$	146
June 30		1,481		1,530		502		459		231		182
September 30		1,938		1,919		490		440		215		178
December 31		1,390		1,311		442		315		215		101

19. Subsequent Events

On January 22, 2003, ComEd issued $350 million of 3.70% First Mortgage Bonds, Series 99, due on February 1, 2008 and $350 million of 5.875% First Mortgage Bonds, Series 100, due on February 1, 2033. These bond issuances were used to refinance long-term debt which had been previously retired during the third and fourth quarters of 2002. As part of these bond issuances, ComEd settled various interest rate swaps for $43 million, which will be recorded as a regulatory asset and will be amortized over the life of the associated debt issuance.

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On January 31, 2003, ComEd called $236 million of its First Mortgage Bonds, Series 88, at a redemption price of 103.863% of the principal amount, plus accrued interest to the March 18, 2003 redemption date. The bonds, which carried an interest rate of 8.375% and had a maturity date of February 15, 2023, are expected to be refinanced with long-term debt.

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, which carried an interest rate of 8.48% and had a maturity date of September 30, 2035, were refinanced with trust preferred securities as discussed below.

On February 17, 2003, ComEd called $160 million of its First Mortgage Bonds, Series 91, at a redemption price of 103.664% of the principal amount, plus accrued interest to the April 15, 2003 redemption date. The bonds, which carried an interest rate of 8% and had a maturity date of April 15, 2023, are expected to be refinanced with long-term debt.

On February 20, 2003, ComEd entered into separate agreements with the City of Chicago (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.

On March 17, 2003, ComEd issued $200 million of trust preferred securities, with an annual distribution rate of 6.35% that are mandatorily redeemable on March 15, 2033.

The Agreement addresses, among other things:

•: ComEd's pending residential delivery services rate proceeding

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

•: Illinois electricity market development

There would be a modification of the methodology used to determine the market value energy credit. That credit is used to determine the price for specified market-based rate offerings by

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

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

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

•: Funding of certain programs for customer and governmental groups

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PECO

Report of Independent Accountants

To the Shareholders and Board of Directors
of PECO Energy Company:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(3)(i) present fairly, in all material respects, the financial position of PECO Energy Company and Subsidiary Companies (PECO) at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(3)(ii) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of PECO's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2, as part of a corporate restructuring undertaken on January 1, 2001 by Exelon Corporation, the parent company of PECO, certain of PECO's operations, assets and liabilities, including those related to power generation and enterprises, were transferred to affiliated companies of PECO.

As discussed in Note 4 to the consolidated financial statements, PECO changed its method of accounting for nuclear outage costs in 2000. As discussed in Note 1 to the consolidated financial statements, PECO changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001.

PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania
January 29, 2003

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PECO Energy Company and Subsidiary Companies
Consolidated Statements of Income

			For the Years Ended December 31,
			2002			2001			2000
			(in millions)
Operating Revenues
	Operating Revenues		$	4,321		$	3,953		$	5,950
	Operating Revenues from Affiliates			12			12			—

		Total Operating Revenues		4,333			3,965			5,950

Operating Expenses
	Purchased Power			231			190			1,413
	Purchased Power from Affiliates			1,438			1,162			—
	Fuel			348			450			714
	Operating and Maintenance			450			494			1,791
	Operating and Maintenance from Affiliates			73			93			—
	Merger-Related Costs			—			—			248
	Depreciation and Amortization			456			416			325
	Taxes Other Than Income			244			161			237

		Total Operating Expenses		3,240			2,966			4,728

Operating Income				1,093			999			1,222

Other Income and Deductions
	Interest Expense			(370	)		(405	)		(463	)
	Interest Expense from Affiliates			—			(8	)		—
	Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership, which holds Solely Subordinated Debentures of the Company			(10	)		(10	)		(8	)
	Equity in Earnings (Losses) of Unconsolidated Affiliates			1			—			(41	)
	Interest Income from Affiliates			—			10			—
	Other, Net			31			36			41

		Total Other Income and Deductions		(348	)		(377	)		(471	)

Income Before Income Taxes and Cumulative Effect of a Change in Accounting Principle				745			622			751
Income Taxes				259			197			268

Income Before Cumulative Effect of a Change in Accounting Principle				486			425			483
Cumulative Effect of a Change in Accounting Principle (net of income taxes of $16)				—			—			24

Net Income				486			425			507
Preferred Stock Dividends				8			10			10

Net Income on Common Stock			$	478		$	415		$	497

See Notes to Consolidated Financial Statements

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PECO Energy Company and Subsidiary Companies
Consolidated Statements of Cash Flows

				For the Years Ended December 31,
				2002			2001			2000
				(in millions)
Cash Flows from Operating Activities
Net Income				$	486		$	425		$	507
Adjustments to reconcile Net Income to Net Cash Flows provided by Operating Activities:
		Depreciation and Amortization			456			416			437
		Cumulative Effect of a Change in Accounting Principle (net of income taxes)			—			—			(24	)
		Provision for Uncollectible Accounts			46			69			68
		Deferred Income Taxes			(92	)		(66	)		103
		Merger-Related Costs			—			—			248
		Deferred Energy Costs			25			29			(79	)
		Equity in (Earnings) Losses of Unconsolidated Affiliates			(1	)		—			41
		Other Operating Activities			6			85			(72	)
		Changes in Working Capital:
			Accounts Receivable		(145	)		(54	)		(264	)
			Repurchase of Accounts Receivable		—			—			(50	)
			Inventories		4			(15	)		(45	)
			Accounts Payable, Accrued Expenses & Other Current Liabilities		22			(133	)		(85	)
			Change in Receivables and Payables to Affiliates, net		79			177			—
			Other Current Assets		(6	)		5			(29	)

Net Cash Flows provided by Operating Activities					880			938			756

Cash Flows from Investing Activities
	Capital Expenditures				(261	)		(248	)		(549	)
	InfraSource, Inc. Acquisitions, net of cash acquired				—			—			(245	)
	Proceeds from Nuclear Decommissioning Trust Funds				—			—			74
	Investment in Nuclear Decommissioning Trust Funds				—			—			(100	)
	Other Investing Activities				9			7			(74	)

Net Cash Flows used in Investing Activities					(252	)		(241	)		(894	)

Cash Flows from Financing Activities
	Issuance of Long-Term Debt				225			1,055			1,021
	Common Stock Repurchases				—			—			(496	)
	Retirement of Long-Term Debt				(571	)		(1,416	)		(557	)
	Change in Receivable and Payable to Affiliates, net				—			25			400
	Change in Short-Term Debt				99			(60	)		—
	Redemptions of Mandatorily Redeemable Preferred Stock				(19	)		(18	)		(19	)
	Change in Restricted Cash				(8	)		(69	)		(80	)
	Dividends on Preferred and Common Stock				(348	)		(352	)		(167	)
	Proceeds from Employee Stock Plans				—			—			47
	Contribution from Parent				30			121			—
	Settlement of Interest Rate Swap Agreements				(5	)		31			—
	Other Financing Activities				—			—			(16	)

Net Cash Flows provided by (used in) Financing Activities					(597	)		(683	)		133

Increase in Cash and Cash Equivalents					31			14			(5	)
Cash Transferred in Restructuring					—			(31	)		—
Cash and Cash Equivalents at beginning of period					32			49			54

Cash and Cash Equivalents at end of period				$	63		$	32		$	49

See Notes to Consolidated Financial Statements

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PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets

			December 31,
			2002			2001
			(in millions)
Assets
Current Assets
	Cash and Cash Equivalents		$	63		$	32
	Restricted Cash			331			323
	Accounts Receivable, net
		Customer		379			286
		Other		39			33
Receivables from Affiliates				—			1
	Inventories, at average cost
		Fossil Fuel		67			72
		Materials and Supplies		8			7
	Other			40			59

		Total Current Assets		927			813

Property, Plant and Equipment, net				4,179			4,057
Deferred Debits and Other Assets
	Regulatory Assets			5,491			5,756
	Investments			19			24
	Pension Asset			41			13
	Other			63			75

		Total Deferred Debits and Other Assets		5,614			5,868

Total Assets			$	10,720		$	10,738

Liabilities and Shareholders' Equity
Current Liabilities
	Notes Payable		$	200		$	101
	Payables to Affiliates			170			187
	Long-Term Debt Due Within One Year			689			548
	Accounts Payable			87			54
	Accrued Expenses			370			397
	Deferred Income Taxes			27			27
	Other			33			21

		Total Current Liabilities		1,576			1,335

Long-Term Debt				4,951			5,438
Deferred Credits and Other Liabilities
	Deferred Income Taxes			2,903			2,938
	Unamortized Investment Tax Credits			24			27
	Non-Pension Postretirement Benefits Obligation			251			239
	Payables to Affiliates			—			44
	Other			126			110

		Total Deferred Credits and Other Liabilities		3,304			3,358

Commitments and Contingencies
Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership, which holds Solely Subordinated Debentures of the Company				128			128
Mandatorily Redeemable Preferred Stock				—			19
Shareholders' Equity
	Common Stock			1,976			1,919
	Receivable from Parent			(1,758	)		(1,878	)
	Preferred Stock			137			137
	Retained Earnings			401			263
	Accumulated Other Comprehensive Income			5			19

		Total Shareholders' Equity		761			460

Total Liabilities and Shareholders' Equity			$	10,720		$	10,738

See Notes to Consolidated Financial Statements

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PECO Energy Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholders' Equity

	Common Stock			Preferred Stock		Receivable from Parent			Deferred Compensation			Retained Earnings			Accumulated Other Comprehensive Income			Treasury Stock			Total Shareholders' Equity
	(in millions)
Balance, December 31, 1999	$	3,577		$	137	$	—		$	(3	)	$	(100	)	$	4		$	(1,705	)	$	1,910
Net Income		—			—		—			—			507			—			—			507
Long-Term Incentive Plan		54			—		—			(9	)		—			—			7			52
Deferred Compensation		—			—		—			5			—			—			—			5
Common Stock Dividends		—			—		—			—			(157	)		—			—			(157	)
Preferred Stock Dividends		—			—		—			—			(10	)		—			—			(10	)
Unicom Merger Consideration		—			—		—			—			(45	)		—			—			(45	)
Common Stock Repurchases		—			—		—			—			(5	)		—			(496	)		(501	)
Stock Option Exercises		—			—		—			—			—			—			19			19
Cancellation of Treasury Shares		(2,175	)		—		—			—			—			—			2,175			—
Other Comprehensive Income, net of income taxes of $(3)		—			—		—			—			—			(5	)		—			(5	)
Reorganization Pursuant to Share Exchange		(7	)		—		—			7			—			—			—			—

Balance, December 31, 2000		1,449			137		—			—			190			(1	)		—			1,775
Net Income		—			—		—			—			425			—			—			425
Common Stock Dividends		—			—		—			—			(342	)		—			—			(342	)
Preferred Stock Dividends		—			—		—			—			(10	)		—			—			(10	)
Receivable from Parent		1,983			—		(1,983	)		—			—			—			—			—
Repayment of Receivable from Parent		—			—		105			—			—			—			—			105
Stock Option Exercises		(26	)		—		—			—			—			—			—			(26	)
Capital Contribution from Parent		121			—		—			—			—			—			—			121
Net Assets Transferred in Restructuring		(1,608	)		—		—			—			—			—			—			(1,608	)
Other Comprehensive Income, net of income taxes of $16		—			—		—			—			—			20			—			20

Balance, December 31, 2001		1,919			137		(1,878	)		—			263			19			—			460
Net Income		—			—		—			—			486			—			—			486
Common Stock Dividends		—			—		—			—			(340	)		—			—			(340	)
Preferred Stock Dividends		—			—		—			—			(8	)		—			—			(8	)
Repayment of Receivable from Parent		—			—		120			—			—			—			—			120
Capital Contribution from Parent		30			—		—			—			—			—			—			30
Allocation of tax benefit from Parent		27			—		—			—			—			—			—			27
Other Comprehensive Income, net of income taxes of $(9)		—			—		—			—			—			(14	)		—			(14	)

Balance, December 31, 2002	$	1,976		$	137	$	(1,758	)	$	—		$	401		$	5		$	—		$	761

See Notes to Consolidated Financial Statements

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PECO Energy Company and Subsidiary Companies
Consolidated Statements of Comprehensive Income

		For the Years Ended December 31,
		2002			2001			2000
		(in millions)
Net Income		$	486		$	425		$	507
Other Comprehensive Income (Loss)
	SFAS 133 Transition Adjustment, net of income taxes of $29	$	—		$	40		$	—
	Cash Flow Hedge Fair Value Adjustment, net of income taxes of $(8) and $(13), respectively		(13	)		(20	)		—
	Unrealized Gain (Loss) on Marketable Securities, net of income taxes of $(1) and $(3), respectively		(1	)		—			(5	)

Total Other Comprehensive Income (Loss)			(14	)		20			(5	)

Total Comprehensive Income		$	472		$	445		$	502

See Notes to Consolidated Financial Statements

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PECO Energy Company and Subsidiary Companies
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data unless otherwise noted)

1. Significant Accounting Policies

Description of Business. Incorporated in Pennsylvania in 1929, PECO Energy Company (PECO) is engaged principally in the production, purchase, transmission, distribution and sale of electricity to residential, commercial, industrial and wholesale customers and the distribution and sale of natural gas to residential, commercial and industrial customers. Pursuant to the Pennsylvania Electricity Generation Customer Choice and Competition Act (Competition Act), the Commonwealth of Pennsylvania has required the unbundling of retail electric services in Pennsylvania into separate generation, transmission and distribution services with open retail competition for generation services. Since the commencement of deregulation in 1999, PECO serves as the local distribution company providing electric distribution services in its franchised service territory in southeastern Pennsylvania and bundled electric service to customers who do not choose an alternate electric generation supplier.

PECO is a wholly-owned subsidiary of Exelon Corporation (Exelon) (see Note 3—Merger). During January 2001, Exelon undertook a corporate restructuring to separate PECO's generation and other competitive businesses from its regulated energy delivery business. As part of the restructuring, the non-regulated operations and related assets and liabilities of PECO, representing the generation and enterprises business segments were transferred to separate subsidiaries of Exelon. As a result, beginning January 2001, the operations of PECO consist of its retail electricity distribution and transmission business in southeastern Pennsylvania and its natural gas distribution business located in the Pennsylvania counties surrounding the City of Philadelphia.

As a result of the corporate restructuring, certain risks and commitments and the financial condition and results of operations of PECO have changed significantly. Additionally as a result of the restructuring, PECO is no longer subject to the risks associated with nuclear insurance, decommissioning, spent fuel disposal and energy commitments, other than its purchased power agreement (PPA) with Exelon Generation Company, LLC (Generation). See Note 19—Segment Information for additional financial information.

Prior to the corporate restructuring effective January 2001, PECO also engaged in the wholesale marketing of electricity on a national basis. Through its Exelon Energy division, PECO was a competitive generation supplier offering competitive energy supply to customers throughout Pennsylvania. PECO's infrastructure services subsidiary, InfraSource, Inc. (InfraSource), formerly Exelon Infrastructure Services, Inc., provided utility infrastructure services to customers in several regions of the United States. PECO owned a 50% interest in AmerGen Energy Company, LLC (AmerGen), a joint venture with British Energy, Inc., a wholly-owned subsidiary of British Energy plc (British Energy), to acquire and operate nuclear generating facilities. PECO also participated in joint ventures which provide communications services in the Philadelphia metropolitan region. As a result of the corporate restructuring effective January 1, 2001, these operations were transferred by PECO to other subsidiaries of Exelon. See Note 2—Corporate Restructuring.

Basis of Presentation. The consolidated financial statements of PECO include the accounts of its majority-owned subsidiaries after the elimination of intercompany transactions. In 2000, PECO generally accounted for its 20% to 50% owned investments and joint ventures, in which it exerted significant influence, under the equity method of accounting. In 2000, PECO consolidated its proportionate interest in its jointly owned electric utility plants. PECO accounts for its less than 20% owned investments under the cost method of accounting. Accounting policies for regulated operations are in accordance with those prescribed by the regulatory authorities having jurisdiction, principally the Pennsylvania Public Utility Commission (PUC), the Federal Energy Regulatory Commission (FERC)

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and the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA).

Accounting for the Effects of Regulation. PECO accounts for all of its regulated electric and gas operations in accordance with the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," (SFAS No. 71) requiring PECO to record in its financial statements the effects of the rate regulation. Use of SFAS No. 71 is applicable to the utility operations of PECO that meet the following criteria: (1) third-party regulation of rates; (2) cost-based rates; and (3) a reasonable assumption that all costs will be recoverable from customers through rates. PECO believes that it is probable that currently recorded regulatory assets will be recovered. If a separable portion of PECO's business no longer meets the provisions of SFAS No. 71, PECO is required to eliminate the financial statement effects of regulation for that portion.

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Areas in which significant estimates have been made include, but are not limited to the accounting for unbilled revenue, derivatives, environmental costs, retirement benefit costs and prior to the corporate restructuring, nuclear decommissioning liabilities.

Revenues. Operating revenues are generally recorded as service is rendered or energy is delivered to customers. At the end of each month, PECO accrues an estimate for the unbilled amount of energy delivered or services provided to its electric and gas customers. See Note 8—Accounts Receivable for further discussion. In 2000, PECO recognized contract revenues and profits on certain long-term fixed-price contracts from its services businesses under the percentage-of-completion method of accounting based on costs incurred as a percentage of estimated total costs of individual contracts.

Purchased Gas Adjustment Clause. PECO's natural gas rates are subject to a fuel adjustment clause designed to recover or refund the difference between the actual cost of purchased gas and the amount included in base rates. Differences between the amounts billed to customers and the actual costs recoverable are deferred and recovered or refunded in future periods by means of prospective quarterly adjustments to rates.

Nuclear Fuel. In 2000, the cost of nuclear fuel was capitalized and charged to fuel expense using the unit of production method. Estimated costs of nuclear fuel storage and disposal at operating plants were charged to fuel expense as the related fuel was consumed.

Stock-Based Compensation. PECO uses the disclosure-only provisions of SFAS No. 123, "Accounting for Stock-Based Compensation" (SFAS No. 123). The table below shows the effect on net income had PECO elected to account for its stock-based compensation plans using the fair value method under SFAS No. 123 for the years ended December 31, 2002, 2001 and 2000:

	2002		2001		2000
Net income—as reported	$	486	$	425	$	507
Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income taxes		13		15		17

Pro forma net income	$	473	$	410	$	490

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Income Taxes. Deferred Federal and state income taxes are provided on all significant temporary differences between book basis and tax basis of assets and liabilities, transactions that reflect taxable income in a year different from book income and tax carryforwards. Investment tax credits previously utilized for income tax purposes have been deferred on PECO's Consolidated Balance Sheets and are recognized in book income over the life of the related property. PECO and its subsidiaries file a consolidated return with Exelon for Federal and certain state income tax returns. Income taxes of the consolidated group are allocated to PECO based on the separate return method (see Note 12—Income Taxes.).

Gains and Losses on Reacquired Debt. Recoverable gains and losses on reacquired debt related to regulated operations are deferred and amortized to interest expense over the period consistent with rate recovery for ratemaking purposes. In 2000, prior to the corporate restructuring, gains and losses on reacquired debt were recognized in PECO's Consolidated Statements of Income as incurred.

Comprehensive Income. Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to shareholders. Comprehensive Income is reflected in the Consolidated Statement of Changes in Shareholders' Equity and Consolidated Statements of Comprehensive Income.

Cash and Cash Equivalents. PECO considers all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents.

Restricted Cash. Restricted cash reflects escrowed cash to be applied to the principal and interest payment on the transition bonds.

Marketable Securities. Marketable securities are classified as available-for-sale securities and are reported at fair value, with the unrealized gains and losses, net of tax, reported in other comprehensive income. Prior to the corporate restructuring in which PECO's nuclear generating stations were transferred to Generation (see Note 2—Corporate Restructuring), unrealized gains and losses on marketable securities held in the nuclear decommissioning trust funds were reported in accumulated depreciation. At December 31, 2002 and 2001, PECO had no held-to-maturity or trading securities.

Property, Plant and Equipment. Property, plant and equipment is recorded at cost. PECO evaluates the carrying value of property, plant and equipment and other long-term assets based upon current and anticipated undiscounted cash flows, and recognizes an impairment when it is probable that such estimated cash flows will be less than the carrying value of the asset. Measurement of the amount of impairment, if any, is based upon the difference between carrying value and fair value. The cost of maintenance, repairs and minor replacements of property are charged to maintenance expense as incurred.

Upon retirement, the cost of regulated property plus removal costs less salvage value, are charged to accumulated depreciation in accordance with regulatory practices. For unregulated property, the cost and accumulated depreciation of property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of the gain or loss on disposition.

Depreciation, Amortization and Decommissioning. Depreciation, including a provision for estimated removal costs as authorized by the PUC, is provided over the estimated service lives of property, plant and equipment on a straight line basis. Annual depreciation provisions for financial

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reporting purposes, expressed as a percentage of average service life for each asset category are presented below:

Asset Category	2002		2001		2000
Electric—Transmission and Distribution	2.09	%	2.13	%	1.82	%
Electric—Generation	—		—		5.15	%
Gas	2.13	%	2.34	%	2.39	%
Common—Gas and Electric	6.40	%	6.26	%	3.60	%
Other Property and Equipment	0.71	%	0.60	%	7.82	%

Amortization of regulatory assets is provided over the recovery period as specified in the related regulatory agreement. In 2000, goodwill associated with acquisitions was amortized over periods from 10 to 20 years. Accumulated amortization of goodwill was $35 million at December 31, 2000. Due to the corporate restructuring, which was effective January 2001, the Goodwill on PECO's Consolidated Balance Sheets was transferred to Exelon Enterprises Company, LLC (Enterprises).

Capitalized Interest. PECO uses SFAS No. 34, "Capitalizing Interest Costs," to calculate the costs during construction of debt funds used to finance its non-regulated construction projects. PECO did not record any capitalized interest in 2002 and 2001, but did record capitalized interest of $2 million in 2000.

Allowance for Funds Used During Construction (AFUDC) is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC of $1 million, $2 million and $2 million in 2002, 2001 and 2000, respectively, was recorded as a charge to construction work in progress and as a non-cash credit to AFUDC which is included in other income and deductions. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.

Capitalized Software Costs. Costs incurred during the application development stage of software projects for software which is developed or obtained for internal use are capitalized. At December 31, 2002 and 2001, capitalized software costs totaled $109 million and $107 million, respectively, net of $48 million and $31 million accumulated amortization, respectively. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, not to exceed ten years. During 2002, 2001 and 2000, PECO amortized capitalized software costs of $17 million, $16 million and $7 million, respectively.

Derivative Financial Instruments. PECO accounts for derivative financial instruments under SFAS No. 133, "Accounting for Derivatives and Hedging Activities" (SFAS No. 133). Under the provisions of SFAS No. 133, all derivatives are recognized on the balance sheet at their fair value unless they qualify for a normal purchases and normal sales exception. Changes in the fair value of the derivative financial instruments are recognized in earnings unless specific hedge accounting criteria are met. A derivative financial instrument can be designated as a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge), or a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). Changes in the fair value of a derivative that is highly effective as, and is designated and qualifies as, a fair value hedge, along with the gain or loss on the hedged asset or liability that is attributable to the hedged risk, are recorded in earnings. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as a cash flow hedge are recorded in other comprehensive income, until earnings are affected by the variability of cash flows being hedged.

In connection with Exelon's Risk Management Policy (RMP), PECO enters into derivatives to manage its exposure to fluctuation in interest rates related to its variable rate debt instruments, changes

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in interest rates related to planned future debt issuances prior to their actual issuance and changes in the fair value of outstanding debt which is planned for early retirement.

For 2000, prior to the corporate restructuring, PECO utilized derivatives to manage the utilization of its available generating capability and provisions of wholesale energy to its affiliates. PECO also utilized energy option contracts and energy financial swap arrangements to limit the market price risk associated with forward energy commodity contracts. Prior to the adoption of SFAS No. 133, PECO applied hedge accounting only if the derivative reduced the risk of the underlying hedged item and was designated at the inception of the hedge, with respect to the hedged item. PECO recognized any gains or losses on these derivatives when the underlying physical transaction affected earnings.

New Accounting Pronouncements. In 2001, the FASB issued SFAS No. 143, "Asset Retirement Obligations" (SFAS No. 143). SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. PECO will adopt SFAS No. 143 on January 1, 2003. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. PECO has evaluated the impact of SFAS No. 143 and has determined that the impact is not material to its financial statements.

In November 2002, the FASB released FASB Interpretation No. (FIN) 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, PECO has adopted disclosure requirements under FIN No. 45 (see Note 18—Commitments and Contingencies), 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.

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 PECO's consolidated financial position, results of operation and cash flows, has not been fully determined.

See Note 4—Adoption of New Accounting Pronouncements and Accounting Changes for discussion of the impact of new accounting pronouncements adopted by PECO.

Reclassifications. Certain prior year amounts have been reclassified for comparative purposes. The reclassifications did not affect net income or shareholders' equity.

2. Corporate Restructuring

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and enterprises business segments, were transferred to Generation and Enterprises, respectively. Additionally, certain operations and assets and liabilities of PECO were transferred to Exelon Business Services Company (BSC). As a result, effective January 1, 2001, the operations of PECO consist of its retail electricity distribution and transmission business in southeastern Pennsylvania, and its natural gas distribution business in the Pennsylvania counties surrounding the City of Philadelphia.

The corporate restructuring had the following effect on PECO's Consolidated Balance Sheet:

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

Net Assets Transferred	$	(1,683	)

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

Return of Capital	$	1,608
Note Receivable		75

Total Consideration	$	1,683

In connection with the restructuring, PECO entered into a PPA with Generation. Under the terms of the PPA, PECO obtains the majority of its electric supply from Generation through 2010. Also, under the terms of the transfer, PECO assigned its rights and obligations under various PPAs and fuel supply agreements to Generation. Generation supplies power to PECO from the transferred generation assets, assigned PPAs and other market sources.

As a result of the corporate restructuring, certain risks and commitments that have been disclosed in Note 18—Commitments and Contingencies and the future financial condition and results of operations changed significantly. PECO is no longer subject to the risks associated with nuclear insurance, decommissioning, spent fuel disposal and energy commitments, other than its PPA with Generation. See Note 19—Segment Information for additional financial information.

3. Merger

On October 20, 2000, Exelon became the parent corporation of PECO and Commonwealth Edison Company (ComEd) as a result of the completion of the transactions contemplated by an Agreement and Plan of Exchange and Merger, as amended (Merger), among PECO, Unicom Corporation (Unicom) and Exelon. As a result of Merger, Exelon became the owner of all of the common stock of PECO.

Merger-Related Costs. In association with the Merger, PECO recorded certain reserves for restructuring costs, that were charged to expense pursuant to FASB Emerging Issue Task Force (EITF) Issue 94-3 "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)."

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PECO's merger-related costs charged to expense in 2000 were $248 million, consisting of $116 million for PECO employee costs and $132 million of direct incremental costs incurred by PECO in conjunction with the Merger. Direct incremental costs represent expenses directly associated with completing the Merger, including professional fees, regulatory approval and settlement costs, and settlement of compensation arrangements. Employee costs represent estimated severance costs and pension and postretirement benefits provided under Exelon's merger separation plans for eligible employees who were expected to be involuntarily terminated before December 2002 due to integration activities of the merged companies. Additional employee severance costs of $18 million were charged to operating and maintenance expense in 2001. Employee costs are being paid from Exelon's pension and post-retirement benefit plans, except for certain benefits such as outplacement services, continuation of health care coverage and educational benefits. As of December 31, 2002 a liability of $1 million is reflected on PECO's balance sheet for payment of these benefits.

A total of 960 PECO positions were expected to be eliminated as a result of the merger, 274 of which related to Generation, 230 of which related to PECO and 456 of which related to Enterprises and corporate support areas. As of December 31, 2002, 858 of the positions had been eliminated, of which 224 related to Generation, 195 related to PECO and 439 related to Enterprises and corporate support areas. Of the remaining 102 positions, 58 were eliminated as a result of normal attrition and 44 positions will not be eliminated due to changes in certain business plans.

4. Adoption of New Accounting Pronouncements and Accounting Changes

SFAS No. 144. In September 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). PECO adopted SFAS No. 144 on January 1, 2002. SFAS No. 144 establishes accounting and reporting standards for both the impairment and disposal of long-lived assets. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001 and its provisions are generally applied prospectively. The adoption of this statement had no effect on PECO's reported financial positions, results of operations or cash flows.

SFAS No. 145. In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections" (SFAS No. 145). SFAS No. 145 eliminates SFAS No. 4 "Reporting Gains and Losses from Extinguishment of Debt" (SFAS No. 4) and thus allows for only those gains or losses on the extinguishment of debt that meet the criteria of extraordinary items to be treated as such in the financial statements. SFAS No. 145 also amends Statement of Financial Accounting Standards No. 13, "Accounting for Leases" (SFAS No. 13) to require sale-leaseback accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. The adoption of SFAS No. 145 required a reclassification of the 2000 extraordinary item of $4 million, net of income taxes, to interest expense and income taxes; otherwise, it had no effect on PECO's reported financial positions, results of operations or cash flows.

SFAS No. 133. SFAS No. 133 applies to all derivative instruments and requires that such instruments be recorded on the balance sheet either as an asset or a liability measured at their fair value through earnings, with special accounting permitted for certain qualifying hedges. On January 1, 2001, PECO adopted SFAS No. 133. PECO deferred a non-cash gain of $40 million, net of income taxes, in accumulated other comprehensive income.

Nuclear Outage Costs. During the fourth quarter of 2000, as a result of the synchronization of accounting policies with Unicom in connection with the Merger, PECO changed its method of accounting for nuclear outage costs to record such costs as incurred. Previously, PECO accrued these costs over the operating unit cycle. As a result of the change in accounting method for nuclear outage costs, PECO recorded income of $24 million, net of income taxes of $16 million. The change is reported as a cumulative effect of a change in accounting principle on the Consolidated Statements of

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Income as of December 31, 2000, representing the balance of the nuclear outage cost reserve at January 1, 2000.

SFAS No. 148. In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123" (SFAS No. 148). SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation and requires disclosures in both annual and interim financial statements regarding the method of accounting for stock-based compensation and the effect of the method on financial results. SFAS No. 148 is effective for financial statements for fiscal years ending after December 15, 2002. As of December 31, 2002, PECO has adopted the additional disclosure requirements of SFAS No. 148 and continues to account for stock-compensation plans under the disclosure only provision of SFAS No. 123.

Change in Accounting Estimates. In December 2002, PECO changed its accounting estimate related to the allowance for uncollectible accounts based on an independently prepared evaluation of the risk profile of PECO's customer accounts receivable. As a result of the new evaluation, the allowance for uncollectible accounts reserve was reduced by $17 million in the fourth quarter of 2002.

5. Acquisitions

Sithe Energies, Inc. Acquisition. On December 18, 2000, PECO acquired 49.9% of the outstanding common stock of Sithe Energies, Inc. (Sithe), an independent power generator, through an intercompany transaction with Exelon for $696 million in cash and $8 million of acquisition costs. The transaction included a Put and Call option for the remaining common stock outstanding exercisable between December 2002 and December 2005, at a price to be determined based on prevailing market conditions.

In conjunction with the corporate restructuring in January 2001, PECO transferred its investment in Sithe and the Put and Call option to Generation.

InfraSource, Inc. Acquisitions. In 2000, InfraSource, Inc. (InfraSource, formerly Exelon Infrastructure Services, Inc.), an unregulated majority owned subsidiary of PECO, acquired the stock or assets of seven utility service contracting companies for an aggregate purchase price of approximately $245 million, net of cash acquired of $9 million, including InfraSource common stock valued at $14 million. The acquisitions were accounted for using the purchase method of accounting. The initial estimate of the excess of purchase price over the fair value of net assets acquired (goodwill) was approximately $216 million.

The allocation of purchase price to the fair value of assets acquired and liabilities assumed in these acquisitions is as follows:

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

Total	$	245

At December 31, 2000 current assets included $70 million of costs and earnings in excess of billings on uncompleted contracts and current liabilities includes $23 million of billings and earnings in excess of costs on uncompleted contracts, related to InfraSource.

In conjunction with the corporate restructuring in January 2001, PECO transferred InfraSource to Enterprises.

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AmerGen Energy Company, LLC. In August 2000, AmerGen completed the purchase of Oyster Creek Generating Station (Oyster Creek) from GPU, Inc. (GPU) for $10 million. Under the terms of the purchase agreement, GPU agreed to fund outage costs not to exceed $89 million, including the cost of fuel, for a refueling outage that occurred in 2000. AmerGen is repaying these costs to GPU in nine equal annual installments through 2009. In addition, AmerGen assumed full responsibility for the ultimate decommissioning of Oyster Creek. At the closing of the sale, GPU provided funding for the decommissioning trust of $440 million. In conjunction with this acquisition, AmerGen has received a fully funded decommissioning trust fund which has been computed assuming the anticipated costs to appropriately decommission Oyster Creek discounted to net present value using the NRC's mandated rate of 2%. AmerGen believes that the amount of the trust fund and investment earnings thereon will be sufficient to meet its decommissioning obligation. GPU is purchasing the electricity generated by Oyster Creek pursuant to a three-year PPA.

In conjunction with the corporate restructuring in January 2001, PECO transferred its investment in AmerGen to Generation.

6. Regulatory Issues

In 2002, the phased process to implement competition in the electric industry continued as mandated by the requirements of the PUC's Final Restructuring Order.

Revenue Neutral Reconciliation Adjustment. As permitted by the Pennsylvania Electric Competition Act, the Pennsylvania Department of Revenue calculated a 2002 Revenue Neutral Reconciliation (RNR) adjustment to the 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 will increase 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.

Customer Choice. The PUC's Final Electric Restructuring Order provided for the phase-in of customer choice of electric generation suppliers (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 and at December 31, 2002, pursuant to the MST rules, 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 from an alternative generation supplier. Customers who purchase energy from an EGS continue to pay a delivery charge. 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.

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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.

In February 2002, New Power notified PECO of its intent to withdraw from providing Competitive Default Service (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.

Rate Reductions and Caps. Under the Final Restructuring Order, retail electric rates were capped at year-end 1996 levels (system-wide average of 9.96 cents/kilowatthour (kWh)) through June 2005. The Final Restructuring Order required PECO to reduce its retail electric rates by 8% from the 1996 system-wide average rate on January 1, 1999. This rate reduction decreased to 6% on January 1, 2000 until January 1, 2001. The transmission and distribution rate component was capped at a system-wide average rate of 2.98 cents/kWh through June 30, 2005. Additionally, generation rate caps, defined as the sum of the applicable transition charge and energy and capacity charge, remain in effect through 2010.

On March 16, 2000, the PUC issued an order authorizing PECO to securitize up to an additional $1 billion of its authorized stranded costs recovery. In accordance with the terms of that order, PECO provided its retail customers with rate reductions of $60 million for calendar year 2001 only.

Under a comprehensive settlement agreement in connection with achieving regulatory approval of the Merger, PECO agreed to $200 million in aggregate rate reductions for all customers in Pennsylvania over the period January 1, 2002 through 2005 and extended the rate caps on PECO's retail electric distribution charges through December 31, 2006.

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7. Supplemental Financial Information

Supplemental Income Statement Information

	For the Years Ended December 31,
	2002			2001		2000
Taxes Other Than Income
Utility(a)	$	207		$	135	$	144
Real estate		27			12		45
Payroll		13			12		27
Other		(3	)		2		21

Total	$	244		$	161	$	237

(a): Represents state utility taxes which are included in Revenue and Taxes Other Than Income.

Other, Net
Investment income	$	26	$	24	$	50
AFUDC, equity and borrowed		1		2		2
Gain (loss) on disposition of assets, net		1		6		(20	)
Settlement of purchased power agreement		—		—		6
Other income		3		4		3

Total	$	31	$	36	$	41

Supplemental Cash Flow Information

		For the Years Ended December 31,
		2002		2001		2000
Cash paid during the year:
	Interest (net of amount capitalized)	$	379	$	416	$	431
	Income taxes (net of refunds)		388		271		261
Non-cash investing and financing:
	Contribution of Receivable from Parent	$	—	$	1,878	$	—
	Net Assets Transferred as a Result of the Corporate Restructuring		—		1,608		—
	Investment in Sithe		—		—		696
	Issuance of InfraSource stock		—		—		14
Depreciation and amortization:
	Property, plant and equipment	$	141	$	135	$	229
	Regulatory assets		308		275		57
	Nuclear Fuel		—		—		112
	Decommissioning		7		6		29
	Goodwill		—		—		10

Total Depreciation and Amortization		$	456	$	416	$	437

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Supplemental Balance Sheet Information

	December 31,
	2002		2001
Regulatory Assets
Competitive transition charge	$	4,639	$	4,947
Recoverable deferred income taxes (see Note 12—Income Taxes)		729		675
Non-pension postretirement benefits		64		71
Reacquired debt costs		53		58
Compensated absences		6		5

Long-Term Regulatory Assets		5,491		5,756
Deferred energy costs (current asset)		31		56

Total	$	5,522	$	5,812

•: Competitive Transition Charges (CTC) represent PECO's stranded costs that the PUC determined would be allowed to be recoverable through regulated rates. These costs are related to the deregulation of the generation portion of the electric utility business in Pennsylvania. The unamortized balance of the CTC of $4.6 billion and $4.9 billion as of December 31, 2002 and 2001, respectively, was recorded on PECO's Consolidated Balance Sheets. The CTC includes Intangible Transition Property sold to PECO Energy Transition Trust, a wholly-owned subsidiary of PECO, in connection with the securitization of PECO's stranded cost recovery. These charges are being amortized through December 31, 2010 with a return on the unamortized balance of 10.75%.
•: Non-pension postretirement benefits represent recoverable curtailment costs associated with a voluntary workforce reduction program in 1994.
•: Reacquired debt costs represent recoverable losses on reacquired debt that are deferred and amortized over the rate-regulatory period, which is over the life of the new debt issued to finance the debt redemption.
•: Deferred energy costs (current asset) are fuel costs recoverable under the purchase gas adjustment clause.

The regulatory asset related to the deferred income taxes did not require a cash outlay of investor supplied funds; consequently, this cost is not earning a rate of return. Recovery of the regulatory asset for loss on reacquired debt is provided for through regulated revenue sources that are based on the pre-open access cost of service. Therefore, this cost is earning a rate of return.

	December 31,
	2002		2001
Accrued Expenses
Taxes Accrued	$	111	$	107
Interest Accrued		112		122
Other Accrued Expenses		147		168

	$	370	$	397

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8. Accounts Receivable

Accounts receivable—Customer at December 31, 2002 and 2001 included unbilled operating revenues of $129 million and $100 million, respectively. The allowance for uncollectible accounts at December 31, 2002 and 2001 was $72 million and $110 million, respectively.

PECO is party to an agreement with a financial institution under which it can sell or finance with limited recourse an undivided interest, adjusted daily, in up to $225 million of designated accounts receivable until November 2005. At December 31, 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 Note 11—Long-Term Debt). PECO retains the servicing responsibility for these receivables. The agreement requires PECO to maintain the $225 million interest, which, if not met, requires 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 and was not required to make any cash deposits.

9. Property, Plant, and Equipment

A summary of property, plant and equipment by classification as of December 31, 2002 and 2001 is as follows:

Asset Category		2002		2001
Electric-Transmission and Distribution		$	4,204	$	4,058
Gas			1,319		1,281
Common			404		399
Construction Work in Progress			138		88
Other Property, Plant and Equipment			19		20

	Total Property, Plant and Equipment		6,084		5,846
	Less Accumulated Depreciation		1,905		1,789

Property, Plant and Equipment, net		$	4,179	$	4,057

10. Notes Payable

	2002			2001			2000
Average borrowings	$	155		$	3		$	186
Average interest rates, computed on daily basis		1.77	%		2.99	%		6.62	%
Maximum borrowings outstanding	$	612		$	471		$	500
Average interest rates, at December 31		1.51	%		2.25	%		7.18	%

PECO, along with Exelon, ComEd and Generation, entered into a $1.5 billion unsecured revolving credit facility on November 22, 2002 with a group of banks. Under the credit facility, each borrower may borrow up to a designated sublimit amount on a revolving credit basis through November 20, 2003. This credit facility 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. At December 31, 2002 PECO's sublimit was $400 million. This credit facility is used primarily to support PECO's commercial paper program. At December 31, 2002 and 2001, the amount of commercial paper outstanding was $200 million and $101 million, respectively. Interest rates on the advances under the credit facility are based on the London Interbank Offering Rate as of the date of the advance.

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11. Long-Term Debt

						December 31,
				Maturity Date		December 31,
			Rates	Maturity Date		2002			2001
Securitized Long-Term Debt
	PETT Transition Bonds Series 1999-A:
		Fixed rates	5.63%-6.13%	2003-2008	(a)	$	2,426		$	2,577
		Floating rates	1.48%-1.55%	2004-2007	(a)		274			310
	PETT Transition Bonds Series 2000-A:		7.63%-7.65%	2009	(a)		750			890
	PETT Transition Bonds Series 2001:		6.52%	2010	(a)		805			805
Other Long-Term Debt
	First and Refunding Mortgage Bonds(b)(c):
		Fixed rates	4.75%-6.63%	2003-2012			1,000			1,027
		Floating rates	1.08%-1.41%	2012			154			154
	Pollution control notes:
		Fixed rates	5.20%-5.30%	2021-2034			157			157
		Floating rates	1.20%	2027			17			17
	Notes payable—accounts receivable agreement		1.42%	2005			61			55

Total Long-Term Debt(d)							5,644			5,992
Unamortized debt discount and premium, net							(4	)		(6	)
Due within one year							(689	)		(548	)

Long-Term Debt						$	4,951		$	5,438

(a): The maturity date represents the expected final payment date which is the date when all principal and interest of the related class of transition bonds is expected to be paid in full in accordance with the expected amortization schedule for the applicable class. The date when all principal and interest must be paid in full for the PETT Bonds Series 1999-A, 2000-A and 2001-A are 2003 through 2009, 2010 and 2010, respectively. The current portion of transition bonds is based upon the expected maturity date.
(b): Utility plant of PECO is subject to the lien of its mortgage indenture.
(c): Includes first mortgage bonds issued under the PECO mortgage indenture securing pollution control notes.
(d): Long-term debt maturities in the period 2003 through 2007 and thereafter are as follows:

2003	$	689
2004		380
2005		503
2006		500
2007		641
Thereafter		2,931

Total	$	5,644

In 2002, PECO exchanged $250 million of 5.95% private placement First and Refunding Mortgage Bonds, due November 1, 2011 for bonds which are registered under the Securities Act. The exchange bonds are identical to the outstanding bonds except for the elimination of certain transfer restrictions and registration rights pertaining to the outstanding bonds. PECO did not receive any cash proceeds from issuance of the exchange bonds. Proceeds from the first mortgage bonds issued in 2001 were used

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to repay a $250 million aggregate principal amount of PECO's First and Refunding Mortgage Bonds having an interest rate of 5.625% and a maturity date of November 1, 2001.

Also in 2002, PECO issued $225 million of 4.75% First and Refunding Mortgage Bonds, due October 1, 2012. This bond issuance repaid commercial paper that was used to pay $222 million of First and Refunding Mortgage Bonds at maturity with a weighted average interest rate of 7.30%. In connection with the issuance of the First and Refunding Mortgage Bonds, PECO settled forward-starting interest rate swaps in the aggregate notional amount of $200 million resulting in a $5 million pre-tax loss recorded in other comprehensive income, which is being amortized over the expected remaining life of the related debt.

In 2001, PECO Energy Transition Trust (PETT), a Delaware business trust and a wholly-owned subsidiary of PECO, refinanced $805 million of floating rate Series 1999-A Transition Bonds through the issuance by PETT of fixed-rate transition bonds (Series 2001-A Transition Bonds). The Series 2001-A Transition Bonds are non-callable, fixed rate securities with an interest rate of 6.52%. The Series 2001-A Transition Bonds have an expected final payment date of September 1, 2010 and a termination date of December 31, 2010. In connection with this refinancing, PECO settled $318 million of a forward-starting interest rate swap resulting in a $6 million gain which is reflected in other income and deductions due to the transaction no longer being probable. Also, in connection with the refinancing, PECO settled a portion of the interest rate swaps and the remaining portion of the forward-starting interest rate swaps resulting in gains of $25 million, which were deferred and are being amortized over the expected remaining lives of the related debt.

In 1999, PECO entered into treasury forwards associated with the anticipated issuance of the Series 2000-A Transition Bonds. On May 2, 2000, these instruments were settled with net proceeds to the counterparties of $13 million which has been deferred and is being amortized over the life of the Series 2000-A Transition Bonds as an increase to interest expense.

In 1998, PECO entered into treasury forwards and forward-starting interest rate swaps to manage interest rate exposure associated with the anticipated issuance of the Series 1999-A Transition Bonds. On March 18, 1999, these instruments were settled with net proceeds of $80 million to PECO which were deferred and are being amortized over the life of the Series 1999-A Transition Bonds as a reduction of interest expense.

At December 31, 2002 and 2001, the aggregate unamortized net gain on the settlement of the PECO swap transactions was $36 million and $55 million, respectively, recorded in Other Comprehensive Income.

In 2000, PECO incurred charges aggregating $6 million ($4 million, net of tax) for prepayment premiums and the write-offs of unamortized deferred financing costs associated with the early retirement of debt that have been recorded in interest expense.

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12. Income Taxes

Income tax expense (benefit) is comprised of the following components:

		For the Year Ended December 31,
		2002			2001			2000
Included in operations:
Federal
	Current	$	305		$	255		$	179
	Deferred		(51	)		(49	)		91
	Investment tax credit, net		(3	)		(3	)		(15	)
State
	Current		46			8			2
	Deferred		(38	)		(14	)		11

		$	259		$	197		$	268

Included in cumulative effects of changes in accounting principles:
Federal
	Deferred	$	—		$	—		$	13
State
	Deferred		—			—			3

		$	—		$	—		$	16

The effective income tax rate varies from the U.S. Federal statutory rate principally due to the following:

		For the Year Ended December 31,
		2002		2001		2000
U.S. Federal statutory rate		35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
	Plant basis differences	(1.5	)	(0.8	)	(0.8	)
	State income taxes, net of Federal income tax benefit	0.7		(0.6	)	2.7
	Amortization of investment tax credit	(0.3	)	(0.4	)	(1.9	)
	Other, net	0.9		(1.5	)	0.7

Effective income tax rate		34.8	%	31.7	%	35.7	%

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The tax effects of temporary differences giving rise to significant portions of PECO's deferred tax assets and liabilities are presented below:

		For the Year Ended December 31,
		2002			2001
Deferred tax liabilities:
	Plant basis difference	$	2,950		$	2,990
	Deferred investment tax credits		24			27
	Unrealized gain on derivative financial instruments		23			15
	Deferred debt refinancing costs		29			31

Total deferred tax liabilities			3,026			3,063

Deferred tax assets:
	Deferred pension and postretirement obligations		(11	)		(12	)
	Other, net		(61	)		(59	)

Total deferred tax assets			(72	)		(71	)

Deferred income taxes (net) on the balance sheet		$	2,954		$	2,992

In accordance with regulatory treatment of certain temporary differences, PECO has recorded a regulatory asset for recoverable deferred income taxes, pursuant to SFAS No. 109, of $729 million and $675 million at December 31, 2002 and 2001, respectively. These recoverable deferred income taxes include the deferred tax effects associated principally with liberalized depreciation accounted for in accordance with the ratemaking policies of the PUC, as well as the revenue impacts thereon, and assume continued recovery of these costs in future rates.

Certain PECO tax returns are under review at the audit and appeals level of the Internal Revenue Service (IRS) and certain state authorities. These reviews by the governmental taxing authorities are not expected to have an adverse impact on the financial condition or result of operations at PECO.

13. Retirement Benefits

PECO has adopted defined benefit pension plans and postretirement welfare benefit plans sponsored by Exelon. In 2001, PECO's former plans were consolidated into the Exelon plans. Essentially all PECO employees are eligible to participate in the Exelon plans. Benefits under these pension plans generally reflect each employee's compensation, years of service, and age at retirement.

The Pension Asset and Non-Pension Postretirement Benefits Obligation on the PECO Consolidated Balance Sheets reflects PECO's obligation from and to the plan sponsor, Exelon. Employee-related assets and liabilities, including both pension and SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other than Pensions," postretirement welfare assets and liabilities, were allocated by Exelon to its subsidiaries based on the number of active employees as of January 1, 2001 as part of Exelon's corporate restructuring. Exelon allocates the components of pension expense to the participating employers based upon several factors, including the percentage of active employees in each participating unit.

See Note 15—Retirement Benefits of the Notes to Exelon's Consolidated Financial Statements for pension and other postretirement benefits information for the Exelon plans.

Approximately $22 million and $(2) million were included in operating and maintenance expense in 2002 and 2001, respectively, for PECO's allocated portion of Exelon's pension and postretirement benefit expense. PECO did not make any pension contributions in 2002 or 2001. In 2000, PECO recorded a net pension benefit of $107 million and a net postretirement benefit cost of $102 million.

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Exelon's costs of providing pension and postretirement benefits are dependent upon a number of factors, such as the rates of return on pension plan assets, discount rate, and the rate of increase in health care costs. The market value of plan assets has been affected by sharp declines in the equity market since the third quarter of 2000. As a result, at December 31, 2002, Exelon was required to recognize an additional minimum liability as prescribed by SFAS No. 87, "Employer's Accounting for Pensions." The liability was recorded as a reduction to common 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 obligations. Based upon the market value of plan assets at December 31, 2002, the amount of the reduction to shareholders' equity (net of income taxes) is $1 billion. The recording of this reduction, at the Exelon holding company level, did not affect net income or cash flow in 2002 or compliance with debt covenants.

PECO participates in a 401(k) savings plan sponsored by Exelon. The plan allows employees to contribute a portion of their pretax income in accordance with specified guidelines. PECO matches a percentage of the employee contribution up to certain limits. The cost of PECO's matching contribution to the savings plan totaled $7 million, $7 million and $11 million in 2002, 2001, and 2000, respectively.

14. Preferred Stock

At December 31, 2002 and 2001, cumulative Preferred Stock of PECO, no par value, consisted of 15,000,000 shares authorized and the amounts set forth below:

				December 31,
				2002	2001	2002		2001
	Current Redemption Price(a)			2002	2001	2002		2001
	Current Redemption Price(a)			Shares Outstanding		Amount
Series (without mandatory redemption)
$4.68	$	104.00		150,000	150,000	$	15	$	15
$4.40		112.50		274,720	274,720		27		27
$4.30		102.00		150,000	150,000		15		15
$3.80		106.00		300,000	300,000		30		30
$7.48		(b	)	500,000	500,000		50		50

				1,374,720	1,374,720		137		137
Series (with mandatory redemption)
$6.12		(c	)	—	185,400		—		19

Total preferred stock				1,374,720	1,560,120	$	137	$	156

(a): Redeemable, at the option of PECO, at the indicated dollar amounts per share, plus accrued dividends.
(b): None of the shares of this series is subject to redemption prior to April 1, 2003.
(c): PECO made the annual sinking fund payments of $19 million on August 1, 2002 and August 1, 2001. At December 31, 2000, shares and principal outstanding were 370,800 and $37 million, respectively.

15. Company—Obligated Mandatorily Redeemable Preferred Securities of a Partnership

At December 31, 2002 and 2001, PECO Energy Capital, L.P. (Partnership), a Delaware limited partnership of which a wholly-owned subsidiary of PECO is the sole general partner, had outstanding

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Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS) as set forth in the following table:

							December 31,
							2002	2001	2002		2001
		Mandatory Redemption Date	Distribution Rate		Liquidation Value		Trust Securities Outstanding		Amount
PECO Energy
	Capital Trust II	2037	8.00	%	$	25	2,000,000	2,000,000	$	50	$	50
PECO Energy
	Capital Trust III	2028	7.38	%		1,000	78,105	78,105		78		78

Total							2,078,105	2,078,105	$	128	$	128

The securities issued by the PECO trusts represent Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS) having a distribution rate and liquidation value equivalent to the trust securities. The COMRPS are the sole assets of these trusts and represent limited partnership interests of PECO Energy Capital, L.P. (Partnership), a Delaware limited partnership. Each holder of a trust's securities is entitled to withdraw the corresponding number of COMRPS from the trust in exchange for the trust securities so held. Each series of COMRPS is supported by PECO's deferrable interest subordinated debentures, held by the Partnership, which bear interest at rates equal to the distribution rates on the related series of COMRPS.

The interest expense on the securities is included in Other Income and Deductions in the Consolidated Statements of Income and is deductible for income tax purposes.

16. Common Stock

At December 31, 2002 and 2001, common stock without par value consisted of 500,000,000 shares authorized and 170,478,507 shares outstanding.

Stock Repurchase. In January 2000, in connection with the Merger, PECO entered into a forward purchase agreement to purchase $500 million of its common stock from time to time. Settlement of this forward purchase agreement was, at PECO's election, on a physical, net share or net cash basis. In May 2000, PECO utilized a portion of the proceeds from the securitization of its stranded cost recovery to physically settle this agreement, resulting in the repurchase of 12 million shares of common stock for $496 million. In connection with the settlement of this agreement, PECO received $1 million in accumulated dividends on the repurchased shares and paid $6 million of interest.

Fund Transfer Restrictions. Under PUHCA, PECO can pay dividends only from retained or current earnings. At December 31, 2002, PECO had retained earnings of $401 million.

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17. Fair Value of Financial Assets and Liabilities

The carrying amounts and fair values of PECO's financial assets and liabilities as of December 31, 2002 and 2001 were as follows:

		2002						2001
		Carrying Amount			Fair Value			Carrying Amount			Fair Value
Non-derivatives:
Liabilities
	Long-term debt (including amounts due within one year)	$	5,640		$	6,264		$	5,986		$	6,199
COMRPS		$	128		$	165		$	128		$	127
Mandatorily Redeemable Preferred Stock		$	—		$	—		$	19		$	10
Derivatives:
	Interest rate swaps	$	(22	)	$	(22	)	$	(19	)	$	(19	)

As of December 31, 2002 and 2001, PECO's carrying amounts of cash and cash equivalents and accounts receivable are representative of fair value because of the short-term nature of these instruments. Fair values of the long-term debt, COMRPS and Mandatorily Redeemable Preferred Stock are estimated based on quoted market prices for the same or similar issues. The fair value of PECO's interest rate swaps is determined using external dealer prices or internal valuation models which utilize assumptions of available market pricing curves.

Financial instruments that potentially subject PECO to concentrations of credit risk consist principally of cash equivalents and customer accounts receivable. PECO places its cash equivalents with high-credit quality financial institutions. Generally, such investments are in excess of the Federal Deposit Insurance Corporation limits. Concentrations of credit risk with respect to customer accounts receivable are limited due to PECO's large number of customers and their dispersion across many industries.

PECO has entered into floating to fixed interest rate swaps to manage interest rate exposure associated with the floating rate series of transition bonds issued to securitize PECO's stranded cost recovery. These interest rate swaps were designated as cash flow hedges. These interest rate swaps had an aggregate fair market value exposure of $22 million at December 31, 2002.

PECO also has interest rate swaps in place to satisfy counterparty credit requirements in regards to the floating rate series of transition bonds which are mirror swaps of each other. These swaps are not designated as cash flow hedges; therefore, they are required to be marked-to-market if there is a difference in their values. Since these swaps are offsetting each other, a mark-to-market adjustment is not expected to occur.

During 2002, PECO entered into forward-starting interest rate swaps, with an aggregate notional amount of $200 million, in anticipation of the issuance of debt. These interest rate swaps were designated as cash flow hedges. In connection with bond issuances in 2002, PECO settled these forward-starting interest rate swaps resulting in a $5 million pretax loss recorded in other comprehensive income, a component of shareholders' equity, which is being amortized over the life of the related debt.

On January 1, 2001, PECO deferred a non-cash gain of $40 million, net of income taxes, in accumulated other comprehensive income to reflect the initial adoption of SFAS No. 133, as amended. SFAS No. 133 is applied to all derivative instruments and requires that such instruments be recorded in the balance sheet either as an asset or a liability measured at their fair value through earnings, with special accounting permitted for certain qualifying hedges.

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For 2001, $6 million ($4 million, net of income taxes), respectively, was reclassified from accumulated other comprehensive income into earnings as a result of forecasted financing transactions no longer being probable.

As of December 31, 2002, $14 million of deferred net gains on derivative instruments accumulated in other comprehensive income are expected to be reclassified to earnings during the next twelve months. Amounts in accumulated other comprehensive income related to interest rate cash flows are reclassified into earnings when the forecasted interest payment occurs.

PECO would be exposed to credit-related losses in the event of non-performance by the counterparties that issued the derivative instruments. The credit exposure of derivatives contracts is represented by the fair value of contracts at the reporting date. PECO's interest rate swaps are documented under master agreements. Among other things, these agreements provide for a maximum credit exposure for both parties. Payments are required by the appropriate party when the maximum limit is reached.

18. Commitments and Contingencies

Commercial Commitments. PECO's commercial commitments as of December 31, 2002 representing commitments triggered by future events, including obligations to make payment on behalf of other parties as well as financing arrangements to secure obligations of PECO, are as follows:

			Expiration within
			Expiration within						After 5 Years
	Total		1 Year		2-3 Years		4-5 Years		After 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)		67		67		—		—		—

Total Commercial Commitments	$	667	$	513	$	—	$	—	$	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.
(b): Letters of Credit (non-debt)—PECO and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
(c): Letters of Credit (Long-Term Debt)—Direct-pay letters of credit issued in connection with variable-rate debt in order to provide liquidity in the event that it is not possible to remarket all of the debt as required following specific events, including changes in the basis of determining the interest rate on the debt.
(d): Insured Long-Term Debt—Borrowings that have been credit-enhanced through the purchase of insurance coverage equal to the amount of principal outstanding plus interest.
(e): Surety Bonds—Guarantees issued related to contract and commercial surety bonds, excluding bid bonds.

Capital Commitments. PECO estimates that it will spend approximately $270 million for capital expenditures in 2003.

208

Energy Commitments. In connection with the corporate restructuring (see Note 2—Corporate Restructuring), PECO entered into a PPA with Generation. Under the terms of the PPA, PECO obtains the majority of its electric supply from Generation through 2010. Also, under the terms of the 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.

Environmental Issues. PECO's operations have in the past and may in the future require substantial capital expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, PECO is generally liable for the costs of remediating environmental contamination of property now or formerly owned by PECO and of property contaminated by hazardous substances generated by PECO. PECO owns or leases a number of real estate parcels, including parcels on which its operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. PECO has identified 28 sites where former manufactured gas plant (MGP) activities have or may have resulted in actual site contamination. PECO is currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.

As of December 31, 2002 and 2001, PECO had accrued $40 million and $37 million, respectively, for environmental investigation and remediation costs, including $28 million and $27 million, respectively, for investigation and remediation at its 28 MGP sites, that currently can be reasonably estimated. PECO cannot reasonably estimate whether it will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by PECO, environmental agencies or others, or whether such costs will be recoverable from third parties.

Leases. Minimum future operating lease payments, which consist primarily of lease payments for vehicles, as of December 31, 2002 were:

2003	$	5
2004		4
2005		3
2006		3
2007		2
Remaining years		3

Total minimum future lease payments	$	20

Rental expense under operating leases totaled $7 million, $2 million and $36 million in 2002, 2001, and 2000, respectively.

Litigation. PECO is involved in various litigation matters. The ultimate outcome of such matters, while uncertain, is not expected to have a material adverse effect on its respective financial condition or results of operations.

19. Segment Information

As a result of the corporate restructuring in January 2001, PECO operates in one segment—energy delivery. Energy delivery consists of the retail electricity distribution and transmission business of PECO in southeastern Pennsylvania and the natural gas distribution business of PECO located in the Pennsylvania counties surrounding the City of Philadelphia. Prior to 2001, PECO operated in two other business segments, generation and enterprises. See Note 2—Corporate Restructuring.

209

Generation consisted of electric generating facilities, energy marketing operations and PECO's interests in Sithe and AmerGen. Enterprises consisted of competitive retail energy sales, energy and infrastructure services, communications and other investments weighted towards the communications, energy services and retail services industries. An analysis and reconciliation of PECO's business segment information to the respective information in the consolidated financial statements are as follows:

	Energy Delivery			Generation			Enterprises		Intersegment Corporate			Eliminations			Consolidated
Total Revenues:
2000	$	3,373		$	2,726		$	1,118	$	—		$	(1,267	)	$	5,950
Intersegment Revenues:
2000	$	4		$	795		$	468	$	—		$	(1,267	)	$	—
Depreciation and Amortization:
2000	$	195		$	98		$	32	$	—		$	—		$	325
Operating Expenses:
2000	$	2,242		$	2,398		$	1,186	$	169		$	(1,267	)	$	4,728
Interest Expense:
2000	$	405		$	32		$	3	$	23		$	—		$	463
Income Taxes:
2000	$	(300	)	$	(111	)	$	166	$	(23	)	$	—		$	(268	)
Net Income/(Loss):
2000(a)	$	430		$	233		$	47	$	(213	)	$	—		$	497
Capital Expenditures:
2000	$	219		$	243		$	64	$	23		$	—		$	549
Total Assets:
2000	$	13,100		$	1,648		$	991	$	(963	)	$	—		$	14,776

(a): Includes non-recurring items of $248 million for Merger-related expenses in 2000.

Equity in earnings of AmerGen and Sithe of $4 million for 2000 are included in the generation business unit's net income. Equity in losses of communications joint ventures of $45 million in 2000 are included in the enterprises business unit's net income.

210

20. Related-Party Transactions

PECO's financial statements reflect a number of related-party transactions as reflected in the table below.

		For Year Ended December 31,
		2002		2001		2000
Operating Revenues from Affiliate
	Generation(1)	$	12	$	12	$	—
Purchased Power from Affiliate
	Generation(2)		1,438		1,162		—
Purchased Power from Unconsolidated Affiliate(3)			—		—		47
O&M from Affiliates
	BSC(4)		49		69		—
	Enterprises(5)		24		24		—
Capitalized Costs
	Enterprises(5)		24		29		—
	BSC(4)		8		—		—
Interest Expense from Affiliates
	ComEd(6)		—		8		—
Interest Income from Affiliates
	Generation(7)		—		6		—
	Other		—		4		—
Cash Dividends Paid to Parent			340		342		—

		December 31,
		2002		2001
Receivables from Affiliates
	Other	$	—	$	1
Payables to Affiliates
	Generation(2)		124		117
	BSC(4)		26		61
	Enterprises(5)		19		9
	Other		1		—
Deferred Credits and Other Liabilities
	BSC		—		44
Shareholders' Equity—Receivable from Parent(8)			1,758		1,878

(1): PECO provides energy to Generation for Generation's own use.
(2): Effective January 1, 2001, PECO entered into a PPA with Generation. See Note 2—Corporate Restructuring for further information regarding the PPA.
(3): PECO purchased power from AmerGen in 2000.
(4): PECO provides services to BSC related to invoice processing. PECO receives a variety of corporate support services from BSC, including legal, human resources, financial and information technology services. Such services are provided at cost, including applicable overhead. Some of these costs are capitalized.
(5): PECO receives services from Enterprises for construction, which are capitalized, and the deployment of automated meter reading technology, which is expensed.

211

(6): At December 31, 2000, PECO had a $400 million payable to ComEd, which was repaid in the second quarter of 2001. The average annual interest rate on this payable for the period outstanding was 6.5%.
(7): PECO received interest income from Generation in 2001 related to a loan.
(8): PECO has a non-interest bearing receivable from Exelon related to the 2001 corporate restructuring. The receivable is expected to be settled over the years 2001 through 2010.

21. Quarterly Data (Unaudited)

The data shown below include all adjustments which PECO considers necessary for a fair presentation of such amounts:

									Income (Loss) Before Cumulative Effect of a Change in Accounting Principle
	Operating Revenues				Operating Income										��
													Net Income
Quarter ended:													Net Income
Quarter ended:	2002		2001		2002		2001		2002		2001		2002		2001
March 31	$	1,020	$	1,051	$	227	$	287	$	89	$	122	$	89	$	122
June 30	$	995	$	906	$	234	$	246	$	93	$	85	$	93	$	85
September 30	$	1,224	$	1,051	$	323	$	258	$	157	$	104	$	157	$	104
December 31	$	1,094	$	957	$	309	$	208	$	147	$	114	$	147	$	114

212

Generation

Report of Independent Accountants

To the Member and Board of Directors of
Exelon Generation Company, LLC:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(4)(i) present fairly, in all material respects, the financial position of Exelon Generation Company, LLC and Subsidiary Companies (Exelon Generation) at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(4)(ii) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of Exelon Generation's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, Exelon Generation's parent company, Exelon Corporation, acquired Unicom Corporation on October 20, 2000 in a business combination accounted for under the purchase method of accounting. The results of the acquired generation-related business are included in the consolidated financial statements of Exelon Generation since the acquisition date.

As discussed in Note 1 to the consolidated financial statements, Exelon Generation changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001.

PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania
January 29, 2003

213

Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Income

			For the Year Ended December 31,
			2002			2001			2000
			(in millions)
OPERATING REVENUES
	Operating Revenues		$	2,631		$	2,723		$	1,723
	Operating Revenues from Affiliates			4,227			4,103			1,551

		Total Operating Revenues		6,858			6,826			3,274

OPERATING EXPENSES
	Purchased Power			2,980			2,924			1,315
	Purchased Power from Affiliates			314			182			52
	Fuel			959			889			479
	Operating and Maintenance			1,504			1,400			754
	Operating and Maintenance from Affiliates			152			128			46
	Depreciation and Amortization			276			282			123
	Taxes Other Than Income			164			149			64

		Total Operating Expense		6,349			5,954			2,833

OPERATING INCOME				509			872			441

OTHER INCOME AND DEDUCTIONS
	Interest Expense			(68	)		(77	)		(39	)
	Interest Expense from Affiliates			(7	)		(38	)		(2	)
	Equity in Earnings of Unconsolidated Affiliates, net			87			90			4
	Interest Income from Affiliates			6			12			—
	Other, Net			77			(20	)		16

		Total Other Income and Deductions		95			(33	)		(21	)

INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES				604			839			420
INCOME TAXES				217			327			160

INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES				387			512			260
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (net of income taxes of $9 and $7, respectively)				13			12			—

NET INCOME			$	400		$	524		$	260

See Notes to Consolidated Financial Statements

214

Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Cash Flow

				For the Year Ended December 31,
				2002			2001			2000
				(in millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income				$	400		$	524		$	260
Adjustments to Reconcile Net Income to Net Cash Flows
	Provided by Operating Activities:
		Depreciation and Amortization, including nuclear fuel			640			682			289
		Cumulative Effect of a Change in Accounting
			Principle (net of income taxes)		(13	)		(12	)		—
		Provision for Uncollectible Accounts			26			16			2
		Deferred Income Taxes			132			23			(60	)
		Equity in (Earnings) Losses of Unconsolidated Affiliates			(87	)		(90	)		(4	)
		Net Realized Losses on Nuclear Decommissioning Trust Funds			32			127			—
		Other Operating Activities			55			(146	)		51
		Changes in Working Capital:
			Accounts Receivable		(263	)		142			(158	)
			Changes in Receivables and Payables to Affiliates, net		(72	)		7			(243	)
			Inventories		(33	)		(28	)		(58	)
			Accounts Payable, Accrued Expenses and Other Current Liabilities		404			26			360
			Other Current Assets		(83	)		3			37

Net Cash Flows provided by Operating Activities					1,138			1,274			476

CASH FLOWS FROM INVESTING ACTIVITIES
		Capital Expenditures			(990	)		(858	)		(288	)
		Investment in Sithe Energies, Inc.			—			—			(704	)
Acquisition of Generating Plants					(445	)		—			—
		Proceeds from Nuclear Decommissioning Trust Funds			1,612			1,624			265
		Investment in Nuclear Decommissioning Trust Funds			(1,824	)		(1,863	)		(380	)
		Note Receivable from Affiliate			(35	)		14			1
		Other Investing Activities			8			40			(58	)

Net Cash Flows used in Investing Activities					(1,674	)		(1,043	)		(1,164	)

CASH FLOWS FROM FINANCING ACTIVITIES
		Change in Note Payable, Affiliate			329			(696	)		696
		Contribution from Minority Interest in Consolidated Subsidiary			43			—			—
		Issuance of Long-Term Debt			30			821			—
		Retirement of Long-Term Debt			(5	)		(4	)		(4	)
		Distribution Paid to Member			(27	)		(132	)		—

Net Cash Flows provided by (used in) Financing Activities					370			(11	)		692

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS					(166	)		220			4
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD					224			4			—

CASH AND CASH EQUIVALENTS AT END OF PERIOD				$	58		$	224		$	4

See Notes to Consolidated Financial Statements

215

Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets

			December 31,
			2002			2001
			(in millions)
ASSETS
CURRENT ASSETS
	Cash and Cash Equivalents		$	58		$	224
	Accounts Receivable, net
		Customer		587			316
		Other		57			122
	Receivables from Affiliates			594			401
	Inventories, at average cost
		Fossil Fuel		140			105
		Materials and Supplies		217			202
	Deferred Income Taxes			7			—
	Other			145			65

		Total Current Assets		1,805			1,435

PROPERTY, PLANT AND EQUIPMENT, NET				4,800			2,003
DEFERRED DEBITS AND OTHER ASSETS
	Nuclear Decommissioning Trust Funds			3,053			3,165
	Investments			657			816
	Receivable from Affiliate			220			291
	Deferred Income Taxes			271			205
	Other			201			223

		Total Deferred Debits and Other Assets		4,402			4,700

TOTAL ASSETS			$	11,007		$	8,138

LIABILITIES AND MEMBER'S EQUITY
CURRENT LIABILITIES
	Long-Term Debt Due within One Year		$	5		$	4
	Accounts Payable			1,089			585
	Payables to Affiliates			10			34
	Notes Payable to Affiliates			863			—
	Accrued Expenses			480			303
	Other			216			171

		Total Current Liabilities		2,663			1,097

LONG-TERM DEBT				2,132			1,021
DEFERRED CREDITS AND OTHER LIABILITIES
	Unamortized Investment Tax Credits			226			234
	Nuclear Decommissioning Liability for Retired Plants			1,394			1,353
	Pension Obligation			37			118
	Non-Pension Postretirement Benefits Obligation			410			384
	Spent Nuclear Fuel Obligation			858			843
	Other			334			280

		Total Deferred Credits and Other Liabilities		3,259			3,212

COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST OF CONSOLIDATED SUBSIDIARY				54			—
MEMBER'S EQUITY
	Membership Interest			2,296			2,315
	Undistributed Earnings			924			524
	Accumulated Other Comprehensive Income (Loss)			(321	)		(31	)

		Total Member's Equity		2,899			2,808

TOTAL LIABILITIES AND MEMBER'S EQUITY			$	11,007		$	8,138

See Notes to Consolidated Financial Statements

216

Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Changes in Divisional/Member's Equity

		Divisional Equity			Membership Interest			Undistributed Earnings		Accumulated Other Comprehensive Income			Total Member's Equity
		(in millions)
Balance, December 31, 1999		$	950		$	—		$	—	$	—		$	950
Net Income			260			—			—		—			260
Unicom Merger Consideration			1,400			—			—		—			1,400

Balance, December 31, 2000			2,610			—			—		—			2,610
Formation of LLC			(2,610	)		2,610			—		—			—
Net Income			—			—			524		—			524
Non-Cash distribution to member			—			(174	)		—		—			(174	)
Distribution to member			—			(121	)		—		—			(121	)
Reclassified net unrealized losses
	On marketable securities, net of income taxes of $(22)		—			—			—		(23	)		(23	)
Other Comprehensive Income, net of income taxes of $(16)			—			—			—		(8	)		(8	)

Balance, December 31, 2001			—			2,315			524		(31	)		2,808
Net Income			—			—			400		—			400
Distribution to member			—			(30	)		—		—			(30	)
Allocation of tax benefit from Member			—			11			—		—			11
Other Comprehensive Income, net of income taxes of $(223)			—			—			—		(290	)		(290	)

Balance, December 31, 2002		$	—		$	2,296		$	924	$	(321	)	$	2,899

See Notes to Consolidated Financial Statements

217

Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Comprehensive Income

		For the Years Ended December 31,
		2002			2001			2000
		(in millions)
Net Income		$	400		$	524		$	260
Other Comprehensive Income
	SFAS 133 Transition Adjustment, net of income taxes of $3	$	—		$	5		$	—
	Cash Flow Hedge Fair Value Adjustment, net of income taxes of $(108) and $29, respectively		(170	)		48			—
	Unrealized Gain (Loss) on Marketable Securities, net of income taxes of $(110) and $(31), respectively		(113	)		(32	)		—
	Realized loss on forward starting interest rate swap net of income taxes of $(1)		—			(2	)		—
	Interest in Other Comprehensive Income of Unconsolidated Affiliates
	Net of income taxes of $(5) and $(16), respectively		(7	)		(27	)		—

Total Other Comprehensive Income			(290	)		(8	)		—

Total Comprehensive Income		$	110		$	516		$	260

See Notes to Consolidated Financial Statements

218

Exelon Generation Company, LLC and Subsidiary Companies
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, unless otherwise noted)

1. Summary of Significant Accounting Policies

Description of Business. Exelon Generation Company, LLC (Generation) is a limited liability company engaged principally in the production and wholesale marketing of electricity in various regions of the United States. In 2001, Generation began trading activities. Generation is wholly-owned by Exelon Corporation (Exelon). In connection with the corporate restructuring by Exelon to separate the regulated energy delivery business of its subsidiaries Commonwealth Edison Company (ComEd) and PECO Energy Company (PECO) from its unregulated businesses, including its generation business, Generation began operations as a separate indirect subsidiary of Exelon effective January 1, 2001 (see Note 3—Corporate Restructuring). Generation has numerous wholly-owned subsidiaries. These subsidiaries were primarily established to hold certain hydro-electric and peaking-unit facilities as well as the 49.9% interest in Sithe Energies, Inc. (Sithe) and 20.99% investment in Keystone Fuels, LLC. In addition, Generation also has a finance company subsidiary, Generation Finance Company, LLC, which provides certain financing for Generation's other subsidiaries. Generation also owns a 50% investment in AmerGen Energy Company, LLC (AmerGen).

Basis of Presentation. The consolidated financial statements of Generation include the accounts of its majority-owned subsidiaries after the elimination of intercompany transactions. Investments and joint ventures in which a 20% to 50% interest is owned and a significant influence is exerted are accounted for under the equity method of accounting. The proportionate interests in jointly-owned electric utility plants are consolidated. Generation owns 100% of all significant consolidated subsidiaries, either directly or indirectly, except Southeast Chicago Energy Project, LLC of which Generation owns 70%. Generation has reflected the third-party interests in the above majority owned investments as minority interests in its Consolidated Statements of Cash Flows, Consolidated Balance Sheets and in Other, Net on the Consolidated Statements of Income.

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. The consolidated financial statements are not necessarily indicative of the financial position, results of operations or net cash flows that would have resulted had the generation-related business been a separate company during the periods presented prior to the corporate restructuring. For periods prior to the restructuring, references to Generation mean the generation-related business of Exelon.

Certain information in these consolidated financial statements relating to the results of operations and financial condition of Generation for periods prior to Exelon's restructuring was derived from the historical financial statements of Exelon. Various allocation methodologies were employed to separate the results of operations and financial condition of the generation-related portion of Exelon's business from the historical financial statements for the periods presented prior to the restructuring. Revenues include the generation component of revenue from Exelon's operations and any generation-related revenues, such as ancillary services and wholesale energy activity. Expenses including fuel and other energy-related costs, including purchased power, operations and maintenance and depreciation and amortization, as well as assets, such as property, plant and equipment, materials and supplies and fuel, were specifically identified for Generation's operations. Various allocations were used to disaggregate other common expenses, assets and liabilities between Generation and Exelon's other businesses, primarily the regulated transmission and distribution operations.

219

Management believes that these allocation methodologies are reasonable; however, had Generation existed as a separate company prior to January 1, 2001, its results could have significantly differed from those presented herein. In addition, future results of operations, financial position and net cash flows could materially differ from the historical results presented.

Segment Information. Generation operates in one business comprising its generation and marketing of energy and energy-related products in the United States.

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Areas in which significant estimates have been made include, but are not limited to the accounting for derivatives, nuclear decommissioning liabilities and estimated service lives for plant.

Revenue Recognition. Operating revenues are generally recorded when service is rendered or energy is delivered to customers. At the end of each month, Generation accrues an estimate for unbilled energy provided to its customers. Premiums received and paid on option contracts and swap arrangements are amortized to revenue and expense over the life of the contracts. Certain of these contracts are considered derivative instruments and are recorded at fair value with subsequent changes in fair value recognized as revenues and expenses unless hedge accounting is applied. Commodity derivatives used for trading purposes are accounted for using the mark-to-market method. Under this methodology, these derivatives are adjusted to fair value, and the unrealized gains and losses are recognized in current period income.

Nuclear Fuel. The cost of nuclear fuel is capitalized and charged to fuel expense using the units of production method. Estimated costs of nuclear fuel storage and disposal for operating plants are charged to expense as the related fuel is consumed.

Emission Allowances. Emission allowances are included in inventories and deferred debits and other assets and are carried at acquisition cost and charged to fuel expense as they are used in operations. Allowances held can be used from years 2003 to 2028. Generation's emission allowances balance as of December 31, 2002 and 2001 was $107 million and $126 million, respectively.

Stock-Based Compensation. Generation uses the disclosure-only provisions of SFAS No. 123, "Accounting for Stock-Based Compensation" (SFAS No. 123). The table below shows the effect on net income had Generation elected to account for its stock-based compensation plans using the fair value method under SFAS No. 123 for the years ended December 31, 2002, 2001 and 2000:

	2002		2001		2000
Net income—as reported	$	400	$	524	$	260
Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income taxes		15		9		10

Pro forma net income	$	385	$	515	$	250

Depreciation and Decommissioning. Depreciation is provided over the estimated service lives of property, plant and equipment on a straight-line basis. Annual depreciation provisions for financial reporting purposes, expressed as a percentage of average service life for each asset category, are presented in the table below. See Note 5—Adoption of New Accounting Pronouncements and

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Accounting Changes for information on service life extensions of Generation's nuclear generating stations.

Asset Category		2002		2001		2000
Electric-Generation		3.65	%	3.11	%	5.02	%

Generation's affiliates PECO and ComEd are currently recovering costs for the decommissioning of nuclear generating stations, excluding AmerGen, through regulated rates. Amounts collected for decommissioning by Generation's affiliates are remitted to Generation and are deposited in trust accounts and invested for funding future decommissioning costs of nuclear generating stations. The majority of the eventual work to decommission Generation's nuclear operating generating stations will occur after 2029.

Generation accounts for the current period's cost of decommissioning related to generating plants previously owned by PECO following common regulatory accounting practices by recording a charge to depreciation expense and a corresponding liability in accumulated depreciation concurrently with decommissioning collections. Financial activity of the decommissioning trust (e.g., investment income and realized and unrealized gains and losses on trust investments) is reflected in Nuclear Decommissioning Trust Funds in Generation's Consolidated Balance Sheets with a corresponding offset recorded to the liability in accumulated depreciation. Under common regulatory practices, the deposit of funds into the decommissioning trust accounts plus the financial activity reflected in Nuclear Decommissioning Trust Funds in Generation's Consolidated Balance Sheets will, over time, establish a corresponding liability in accumulated depreciation reflecting the cost to decommission the nuclear generating stations previously owned by PECO. Generation will adopt SFAS No. 143, "Asset Retirement Obligations" (SFAS No. 143) as of January 1, 2003. See "New Accounting Pronouncements" within this note for a discussion as to how this standard will change the accounting for nuclear decommissioning costs.

Regulatory accounting practices for the nuclear generating stations previously owned by ComEd were discontinued as a result of an ICC order capping ComEd's ultimate recovery of decommissioning costs. See Note 9—Nuclear Decommissioning and Spent Fuel Storage regarding regulatory accounting practices for nuclear generating stations transferred by ComEd to Generation. The difference between the current decommissioning cost estimate and the decommissioning liability recorded in accumulated depreciation for the former ComEd operating stations is being amortized to depreciation expense on a straight-line basis over the remaining lives of the stations. The current decommissioning cost estimate (adjusted annually to reflect inflation) for the former ComEd retired units recorded in deferred credits and other liabilities is accreted to depreciation expense. Financial activity of the decommissioning trust related to Generation's nuclear generating stations no longer accounted for under common regulatory practices (e.g., investment income and realized and unrealized gains and losses on trust investments) is reflected in Nuclear Decommissioning Trust Funds in Generation's Consolidated Balance Sheets with a corresponding gain or expense recorded in Generation's Consolidated Income Statement or in other comprehensive income. The offset to the financial activity in the decommissioning trust funds is summarized as follows:

•: Interest income is recorded in other income and deductions,
•: Realized gains and losses are recorded in other income and deductions,
•: Unrealized gains and losses are recorded in other comprehensive income, and
•: Trust fund operating expenses are recorded in operation and maintenance expense

Generation believes that the amounts being recovered from customers through electric rates along with the earnings on the trust funds will be sufficient to fully fund its decommissioning obligations.

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Property, Plant and Equipment. Property, plant and equipment is recorded at cost. Generation evaluates the carrying value of property, plant and equipment and other long-term assets based upon current and anticipated undiscounted cash flows, and recognizes an impairment when it is probable that such estimated cash flows will be less than the carrying value of the asset. Measurement of the amount of impairment, if any, is based upon the difference between the carrying value and fair value. The cost of maintenance, repairs and minor replacements of property is charged to maintenance expense as incurred.

The cost and accumulated depreciation of property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of the gain or loss on disposition (see Note 7—Property, Plant and Equipment).

Research and Development. Research and development costs are charged to expense as incurred.

Capitalized Interest. Generation uses SFAS No. 34, "Capitalizing Interest Costs," to calculate the costs during construction of debt funds used to finance its construction projects. Generation recorded capitalized interest of $24 million, $17 million and $2 million in 2002, 2001 and 2000, respectively.

Capitalized Software Costs. Costs incurred during the application development stage of software projects which are developed or obtained for internal use are capitalized. Generation had not recorded any capitalized software costs prior to 2002. At December 31, 2002 net capitalized software costs totaled $28 million, reflecting $10 million in accumulated amortization. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, not to exceed 10 years. During 2002 Generation's amortization of amortized capitalized software was $10 million.

Income Taxes. Deferred Federal and state income taxes are provided on all significant temporary differences between the book basis and tax basis of assets and liabilities, transactions that reflect taxable income in a year different from book income and tax carryforwards. Investment tax credits previously utilized for income tax purposes have been deferred on Generation's consolidated balance sheet and are recognized in income over the life of the related property. Generation and its subsidiaries file a consolidated return with Exelon for Federal and certain state income tax returns. Income taxes of the consolidated group are allocated to Generation based on the separate return method. See Note 11—Income Taxes.

Cash and Cash Equivalents. Generation considers all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents.

Marketable Securities. Marketable securities are classified as available-for-sale securities and are reported at fair value, with the unrealized gains and losses, net of tax, reported in other comprehensive income. The cost of these securities is determined on the basis of specific identification. At December 31, 2002 and 2001, Generation had no held-to-maturity or trading securities.

Unrealized gains and losses on marketable securities held in the nuclear decommissioning trust funds associated with the former PECO plants are reported in accumulated depreciation. Unrealized gains and losses on marketable securities held in the nuclear decommissioning trust funds associated with the former ComEd plants are reported in accumulated other comprehensive income.

Inventories. Inventories, which consist primarily of fuel and materials and supplies, are valued at the lower of cost or market and are stated on the average cost method. Provisions are made for obsolete and slow moving inventory.

Comprehensive Income. Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to the member. Comprehensive income primarily relates to unrealized gains or losses on securities held in nuclear decommissioning trust funds and unrealized gains and losses on cash flow hedge instruments.

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Derivative Financial Instruments. Generation accounts for derivative financial instruments under SFAS No. 133, "Accounting for Derivatives and Hedging Activities" (SFAS No. 133). Under the provisions of SFAS No. 133, all derivatives are recognized on the balance sheet at their fair value unless they qualify for a normal purchases and normal sales exception. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time, and price is not tied to an unrelated underlying derivative. Changes in the fair value of the derivative financial instruments that do not qualify for a normal purchase and normal sales exception are recognized in earnings unless specific hedge accounting criteria are met. A derivative financial instrument can be designated as a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge), or a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). Changes in the fair value of a derivative that is highly effective as, and is designated and qualifies as, a fair value hedge, along with the gain or loss on the hedged asset or liability that is attributable to the hedged risk, are recorded in earnings. Changes in the fair value of a derivative that is highly effective as, and is designated as and qualifies as a cash flow hedge are recorded in other comprehensive income, until earnings are affected by the variability of cash flows being hedged.

In connection with Exelon's RMP, Generation enters into derivatives to manage its exposure to fluctuations in interest rates related to its variable rate debt instruments, changes in interest rates related to planned future debt issuances prior to their actual issuance and changes in the fair value of outstanding debt which is planned for early retirement. As it relates to energy transactions, Generation utilizes derivatives to manage the utilization of its available generating capability and provisions of wholesale energy to its affiliates. Generation also utilizes energy option contracts and energy financial swap arrangements to limit the market price risk associated with forward energy commodity contracts. Additionally, Generation enters into certain energy related derivatives for trading or speculative purposes.

As part of Generation's energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its 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. While these contracts are considered derivative financial instruments under SFAS No. 133, the majority of these transactions have been designated as "normal purchases" or "normal sales" and are not subject to the provisions of SFAS No. 133. Under these contracts, Generation recognizes gains or losses when the underlying physical transaction affects earnings. Revenues and expenses associated with market price risk management contracts are amortized over the terms of such contracts. Commitments under these contracts are discussed in Note 13—Commitments and Contingencies. The remainder of these contracts are generally considered cash flow hedges under SFAS No. 133. To the extent that the hedges are effective, changes in the fair value of these contracts are recorded in other comprehensive income, until earnings are affected by the variability of cash flows being hedged.

Additionally, during 2001, as part of the creation of Generation's energy trading operation, Generation began to enter into contracts to buy and sell energy for trading purposes subject to limits. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.

Prior to the adoption of SFAS No. 133, Generation applied hedge accounting only if the derivative reduced the risk of the underlying hedged item and was designated at the inception of the hedge, with respect to the hedged item. Generation recognized any gains or losses on these derivatives when the underlying physical transaction affected earnings.

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Contracts entered into by Generation to limit market risk associated with forward energy commodity contracts are reflected in the financial statements at the lower of cost or market using the accrual method of accounting. Under these contracts, Generation recognizes any gains or losses when the underlying physical transaction affects earnings. Revenues and expenses associated with market price risk management contracts are amortized over the terms of such contracts.

New Accounting Pronouncements. In 2001, the FASB issued SFAS No. 143. SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. Generation 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 Generation's nuclear generating plants as well as certain other long-lived assets.

As it relates to nuclear decommissioning, the effect of this 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 represent an obligation for the future decommissioning of the plants and, as a result, accretion expense will be accrued on this liability until such time as 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 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 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 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 is expected to result in an increase in expense.

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In November 2002, the FASB released FASB Interpretation No. (FIN) 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. Generation has adopted the disclosure requirements under FIN No. 45, (see Note 13—Commitments and Contingencies) 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.

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 Generation's consolidated financial position, results of operations and cash flows, has not been fully determined.

In September 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). Generation adopted SFAS No. 144 on January 1, 2002. SFAS No. 144 establishes accounting and reporting standards for both the impairment and disposal of long-lived assets. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001 and its provisions are generally applied prospectively. The adoption of SFAS No. 144 had no effect on Generation's reported financial position, results of operations or cash flows.

Reclassifications. Certain prior year amounts have been reclassified for comparative purposes. The reclassifications did not affect net income or member's equity.

2. Merger

On October 20, 2000, Exelon became the parent corporation for PECO and ComEd as a result of the completion of the transactions contemplated by the Agreement and Plan of Exchange and Merger, as amended (Merger Agreement) among PECO, Unicom Corporation and Exelon. The Merger was accounted for using the purchase method of accounting, with PECO as acquirer.

The fair value of the assets acquired and liabilities assumed in the merger associated with the generation-related business of ComEd are summarized below:

Current assets	$	704
Property, plant and equipment		64
Nuclear fuel		669
Deferred debits and other assets		3,682

		5,119

Current liabilities		632
Deferred debits and other liabilities		3,086

		3,718

Net generation-related assets	$	1,401

Generation has included the generation-related assets and liabilities of ComEd and the related results of operations in its consolidated financial statements beginning October 20, 2000. Generation's Statement of Changes in Member's Equity reflects the generation-related impacts of the Merger as a capital contribution from Exelon.

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Merger-Related Costs. Generation has included the generation-related assets and liabilities of ComEd and the related results of operations in its consolidated financial statements beginning October 20, 2000. Generation's Statement of Changes in Divisional/Member's Equity reflects the generation-related impacts of the Merger as a capital contribution from Exelon.

In association with the Merger, Exelon recorded certain reserves for restructuring costs. The reserves associated with PECO were charged to expense pursuant to FASB Emerging Issue Task Force (EITF) Issue 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)"; while the reserves associated with Unicom were recorded as part of the application of purchase accounting and did not affect results of operations, consistent with EITF Issue 95-3, "Recognition of Liabilities in Connection with a Purchase Business Combination."

Merger costs charged to expense. PECO's merger-related costs charged to expense in 2000 were $248 million, of which $65 million related to Generation. PECO's merger-related costs consisted of $116 million for PECO employee costs and $132 million of direct incremental costs incurred by PECO in conjunction with the merger transaction. Direct incremental costs represent expenses directly associated with completing the Merger, including professional fees, regulatory approval and settlement costs, and settlement of compensation arrangements. Employee costs represent estimated severance costs and pension and postretirement benefits provided under Exelon's merger separation plans for eligible employees who were expected to be involuntarily terminated before December 2002 due to integration activities of the merged companies. Additional employee severance costs of $48 million, primarily related to PECO employees, were charged to operating and maintenance expense in 2001, and a $10 million reduction in the estimated liability related to Generation employees was recorded in operating and maintenance expense in the first quarter of 2002. Employee costs are being paid from Exelon's pension and postretirement benefit plans, except for certain benefits such as outplacement services, continuation of health care coverage and educational benefits. As of December 31, 2002 a liability of $1 million is reflected on Generation's balance sheet for payment of these benefits.

A total of 960 PECO positions were expected to be eliminated as a result of the merger, 274 of which related to Generation. As of December 31, 2002, 858 of the positions had been eliminated, of which 224 related to Generation. Generation's remaining 50 positions were eliminated as a result of normal attrition and changes in certain business plans.

Merger costs included in purchase price allocation. The purchase price allocation as of December 31, 2000 included a liability of $307 million for Unicom employee costs, of which $121 million related to Generation, and liabilities of approximately $39 million for estimated costs of exiting various business activities of former Unicom activities that were not compatible with the strategic business direction of Exelon.

During 2001, Exelon, ComEd and Generation finalized plans for consolidation of functions, including negotiation of an agreement with the International Brotherhood of Electrical Workers Local 15 regarding severance benefits to union employees. In January of 2001, ComEd transferred a portion of its employee related liabilities to Generation, Enterprises and Business Services Company (BSC) as part of the corporate restructuring. In the third quarter of 2002, Generation reduced its reserve by $2 million due to the elimination of identified positions through normal attrition, which did not require payments under Exelon's merger separation plans, and a determination that certain positions would not

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be eliminated by the end of 2002 as originally planned due to a change in certain business plans. In 2001 and 2002, Generation recorded adjustments to the its Unicom employee cost liability as follows:

			Adjustments
	Original Estimate		Adjustments						Adjusted Liabilities
	Original Estimate		2001(a)			2002(a)			Adjusted Liabilities
Employee severance payments	$	45	$	(12	)	$	(2	)	$	31
Other benefits		5		2			—			7

Employee severance payments and other benefits		50		(10	)		(2	)		38
Actuarially determined pension and postretirement costs		71		(25	)		—			46	(b)

Unicom employee cost—generation	$	121	$	(35	)	$	(2	)	$	84

(a): The decrease is a result of the elimination of identified positions through normal attrition and changes in certain business plans.
(b): The reduction reflects lower estimated pension and post retirement welfare benefits reflecting revised actuarial estimates.

The following table provides a reconciliation of the reserve for employee severance and other benefits associated with the Merger:

Adjusted employee severance and other benefits reserve	$	38
Payments to employees in 2001		(9	)
Payments to employees in 2002		(22	)

Employee severance and other benefits reserve as of December 31, 2002(a)	$	7

(a): Relates to certain benefits that are being paid over a period of years.

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The following table provides a reconciliation of Generation's portion of the former Unicom positions eliminated as a result of the Merger:

Estimate at October 20, 2000	1,073
2001 adjustments(a)	(197	)

Total positions	876

Employees terminated in 2000	182
Employees terminated in 2001	91
Employees terminated in 2002	479
2002 Normal attrition	75
Business plan changes(b)	49

Total positions	876

(a): The decrease is a result of the elimination of identified positions through normal attrition and changes in certain business plans.
(b): The reduction is due to a determination in the third quarter of 2002, that certain positions would not be eliminated by the end of 2002 as originally planned due to a change in certain business plans.

3. Corporate Restructuring

During January 2001, Exelon undertook a corporate restructuring to separate its generation and other competitive businesses from its regulated energy delivery businesses conducted by ComEd and PECO. As part of the restructuring, the generation-related operations, employees, assets, liabilities, and certain commitments of Exelon were transferred to Generation.

The assets and liabilities transferred to Generation as of January 1, 2001 were as follows:

Assets
Current assets		$	1,285
Property, plant and equipment			831
Nuclear fuel			896
Nuclear decommissioning trust funds			3,127
Investments			762
Deferred income taxes			337
Note receivable from affiliate			363
Other noncurrent assets			153

	Total assets transferred		7,754

Liabilities
Note payable to member			696
Current liabilities			1,146
Long-term debt			205
Decommissioning obligation for retired plants			1,301
Other noncurrent liabilities			1,970

	Total liabilities transferred		5,318

	Net assets transferred	$	2,436

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On January 1, 2001, a non-cash distribution of $174 million was made in connection with the elimination of certain intercompany transactions.

In connection with the corporate restructuring, ComEd and PECO also assigned their respective rights and obligations under various purchased power and fuel supply agreements to Generation. Additionally, Generation entered into purchased power agreements (PPAs) to supply the capacity and energy requirements of ComEd and PECO.

4. Acquisitions and Dispositions

Sithe New England Holdings Acquisition

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. The preliminary purchase price for the Sithe New England assets consisted of a $534 million note to Sithe, $14 million of direct acquisition costs and an $166 million adjustment to Generation's investment in Sithe related to Sithe New England. Additionally, Generation will assume various Sithe guarantees related to an equity contribution agreement between Sithe New England and Sithe Boston Generating, LLC (SBG), a project subsidiary of Sithe New England. The equity contribution agreement requires, among other things, that Sithe New England, upon the occurrence of certain events, contribute up to $38 million of equity for the purpose of completing the construction of two generating facilities. SBG has a $1.25 billion credit facility (SBG Facility), most of which is available to finance the construction of these two generating facilities. The $1.0 billion of debt outstanding under the facility at December 31, 2002 is reflected on Generation's Consolidated Balance Sheet. Sithe New England owns 4,066 megawatts (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.

The allocation of preliminary purchase price to the fair value of assets acquired and liabilities assumed in the acquisition is as follows:

Current Assets (including $12 of cash acquired)	$	82
Property, Plant and Equipment		1,889
Deferred Debits and Other Assets		62
Current Liabilities		(159	)
Deferred Credits and Other Liabilities		(124	)
Long-Term Debt		(1,036	)

Total Purchase Price	$	714

The SBG Facility provides that if these construction projects are not completed by June 12, 2003, the SBG Facility lenders will have the right, but will not be required, to, among other things, declare all amounts then outstanding under the SBG Facility and the interest rate swap agreements to be due. Generation believes that the construction projects will be substantially complete by June 12, 2003, but that all of the approvals required under the SBG Facility may not be issued by that date. Generation is currently evaluating whether the requirements of the SBG Facility relating to the construction projects can be satisfied by June 12, 2003. In the event that the requirements are not expected to be satisfied by June 12, 2003, Generation will contact the SBG Facility lenders concerning an amendment or waiver of these provisions of the SBG Facility. Generation currently expects that arrangements for such an amendment or waiver, if necessary, can be successfully negotiated with the SBG Facility lenders.

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Acquisition of Generating Plants from TXU

On April 25, 2002, Generation acquired two natural-gas and oil-fired plants from TXU Corp. (TXU) for an aggregate purchase price of $443 million. The purchase included the 893-megawatt Mountain Creek Steam Electric Station in Dallas and the 1,441-megawatt 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 will make fixed capacity payments, variable expense payments, and will provide fuel to Generation in return for exclusive rights to the energy and capacity of the generation plants. Substantially all of the purchase price has been allocated to property, plant and equipment.

AmerGen Energy Company, LLC

In August 2000, AmerGen, a joint venture with British Energy, Inc., a wholly-owned subsidiary of British Energy plc, (British Energy), completed the purchase of Oyster Creek Generating Station (Oyster Creek) from GPU, Inc. (GPU) for $10 million. Under the terms of the purchase agreement, GPU agreed to fund outage costs of $89 million, including the cost of fuel, for a refueling outage that occurred in 2000. AmerGen is repaying these costs to GPU in equal annual installments through 2009. In addition, AmerGen assumed full responsibility for the ultimate decommissioning of Oyster Creek. At the closing of the sale, GPU provided funding for the decommissioning trust of $440 million. In conjunction with this acquisition, AmerGen has received a fully funded decommissioning trust fund which has been computed assuming the anticipated costs to appropriately decommission Oyster Creek discounted to net present value using the Nuclear Regulatory Commission's (NRC) mandated rate of 2%. AmerGen believes that the amount of the trust fund and investment earnings thereon will be sufficient to meet its decommissioning obligation. GPU is purchasing the electricity generated by Oyster Creek pursuant to a three-year PPA, which expires on March 31, 2003.

5. Adoption of New Accounting Pronouncements and Accounting Changes

EITF Issue 02-3

In the second quarter of 2002, Generation adopted the provision of EITF Issue 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 02-3) issued by EITF in June 2002 that requires revenues and energy costs related to energy trading contracts to be presented on a net basis in the income statement. Prior to the adoption, revenues from trading activities were presented in Revenue and the energy costs related to energy trading were presented as either Purchased Power or Fuel expense on Generation's Consolidated Statements of Income. For comparative purposes, energy costs related to energy trading have been reclassified in prior periods to revenue to conform to the net basis of presentation required by EITF 02-3. As Generation commenced trading activities in April 2001, $207 million of purchased power expense and $15 million of fuel expense, respectively, was reclassified and reflected as a reduction to revenue for the year ended December 31, 2001.

SFAS No. 144

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SFAS No. 145

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections" (SFAS No. 145). SFAS No. 145 eliminates SFAS No. 4 "Reporting Gains and Losses from Extinguishment of Debt" and thus allows for only those gains or losses on the extinguishment of debt that meet the criteria of extraordinary items to be treated as such in the financial statements. SFAS No. 145 also amends Statement of Financial Accounting Standards No. 13, "Accounting for Leases" to require sale-leaseback accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions.

SFAS No. 133

SFAS No. 133 applies to all derivative instruments and requires that such instruments be recorded on the balance sheet either as an asset or a liability measured at their fair value through earnings, with special accounting permitted for certain qualifying hedges. On January 1, 2001, Generation adopted SFAS No. 133. Generation recognized a non-cash gain of $12 million, net of income taxes, in earnings and deferred a non-cash gain of $4 million, net of income taxes, in accumulated other comprehensive income and PECO deferred a non-cash gain of $40 million, net of income taxes, in accumulated other comprehensive income.

SFAS No. 148

In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123" (SFAS No. 148). SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation and requires disclosures in both annual and interim financial statements regarding the method of accounting for stock-based compensation and the effect of the method on financial results. SFAS No. 148 is effective for financial statements for fiscal years ending after December 15, 2002. As of December 31, 2002, Generation has adopted the additional disclosure requirements of SFAS No. 148 and continues to account for stock-compensation plans under the disclosure only provision of SFAS No. 123.

Changes in Accounting Estimates

Effective April 1, 2001, Generation changed its accounting estimates related to the depreciation and decommissioning of certain generating stations. The estimated service lives were extended by 20 years for three nuclear stations, by periods of up to 20 years for certain fossil stations and by 50 years for a pumped storage station. Effective July 1, 2001, the estimated service lives were extended by 20 years for the remainder of Generation's operating nuclear stations. These changes were based on engineering and economic feasibility studies performed by Generation 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, which are generally 20 years. The estimated annualized reduction in expense from the change is $132 million ($79 million, net of income taxes).

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6. Supplemental Financial Information

Supplemental Income Statement Information

	For the Year Ended December 31,
	2002			2001			2000
Taxes Other Than Income
Real estate	$	102		$	94		$	32
Payroll		46			38			27
Other		16			17			5

Total	$	164		$	149		$	64

Equity in Earnings of Unconsolidated Affiliates
AmerGen	$	64		$	69		$	4
Sithe		23			21			—

Total	$	87		$	90		$	4

Other, Net
Investment income	$	85		$	(8	)	$	14
Other income (expense)		(8	)		(12	)		2

Total	$	77		$	(20	)	$	16

Supplemental Cash Flow Information

		For the Year Ended December 31,
		2002			2001		2000
Cash paid (received) during the year:
	Interest (net of amount capitalized)	$	63		$	74	$	35
	Income taxes (net of refunds)	$	(37	)	$	335	$	—
Non-cash investing and financing activities:
	Capital Lease Obligations	$	52		$	—	$	—
	Contribution of Land from Minority Interest of Consolidated Subsidiary		12			—		—
	Note Issued to Sithe in the Sithe New England Acquisition		534			—		—
Depreciation and amortization:
	Property, plant and equipment	$	146		$	145	$	94
	Nuclear fuel		374			393		149
	Decommissioning		120			144		46

Total Depreciation and Amortization		$	640		$	682	$	289

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Supplemental Balance Sheet Information

	December 31,
	2002		2001
Investments
Investment in Sithe	$	478	$	700
Investment in AmerGen		160		95
Other		19		21

Total	$	657	$	816

	December 31,
	2002		2001
Accrued Expenses
Taxes Accrued	$	203	$	90
Other		277		213

Total	$	480	$	303

Fund Transfer Restrictions. Under PUHCA, Generation can pay dividends only from undistributed or current earnings. At December 31, 2002, Generation had undistributed earnings of $924 million.

7. Property, Plant and Equipment

A summary of property, plant and equipment by classification is as follows:

Asset Category		2002		2001
Electric-Generation		$	5,678	$	4,344
Nuclear Fuel			3,112		2,681
Construction Work in Progress			2,179		610
Other Property, Plant and Equipment			52		—

Total Property, Plant and Equipment			11,021		7,635
	Less Accumulated Depreciation (including accumulated amortization of nuclear fuel of $2,212 and $1,838 as of December 31, 2002 and 2001, respectively)		6,221		5,632

Property, Plant and Equipment, net		$	4,800	$	2,003

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8. Jointly Owned Facilities—Property, Plant and Equipment

Generation's ownership interest in jointly owned generation plant as of December 31, 2002 and 2001 were as follows:

		Production Plant
December 31, 2002		Production Plant
December 31, 2002		Peach Bottom			Salem			Keystone			Conemaugh			Quad Cities
Operator			Generation			PSE&G			Reliant			Reliant			Generation
Participating Interest			50	%		42.59	%		20.99	%		20.72	%		75	%
Generation's Share:
Plant		$	417		$	44		$	131		$	214		$	171
	Accumulated Depreciation	$	243		$	12		$	117		$	145		$	4
	Construction Work in Progress	$	52		$	36		$	28		$	1		$	35

		Production Plant
December 31, 2001		Production Plant
December 31, 2001		Peach Bottom			Salem			Keystone			Conemaugh			Quad Cities
Operator			Generation			PSE&G			Reliant			Reliant			Generation
Participating Interest			50	%		42.59	%		20.99	%		20.72	%		75	%
Generation's Share:
Plant		$	387		$	12		$	121		$	193		$	96
	Accumulated Depreciation	$	220		$	4		$	98		$	124		$	10
	Construction Work in Progress	$	13		$	53		$	13		$	12		$	52

Generation's undivided ownership interests are financed with Generation funds and, when placed in service, all operations are accounted for as if such participating interests were wholly-owned facilities. Direct expenses of the jointly owned plants are included in the corresponding operating expenses on the Consolidated Income Statements.

9. Nuclear Decommissioning and Spent Fuel Storage

Generation has an obligation to decommission its nuclear power plants. Generation's current estimate of its nuclear facilities' decommissioning cost for its owned nuclear power plants is $7.4 billion in current year (2003) dollars. Based on the extended license lives of the nuclear plants, expenditures are expected to occur primarily when the operating plants are decommissioned, during the period 2029 through 2056. ComEd and PECO collect decommissioning costs through regulated rates. Such collections are remitted to Generation for deposit into the nuclear decommissioning trust funds, which will be used to fund future decommissioning costs. Under ComEd and PECO's rates in effect through December 31, 2002, ComEd and PECO collected approximately $102 million in 2002 from customers in total. At December 31, 2002, the decommissioning liability, recorded in Accumulated Depreciation and Deferred Credits and Other Liabilities on Generation's Consolidated Balance Sheets, was $2.8 billion and $1.4 billion, respectively. At December 31, 2001, the decommissioning liability, recorded in Accumulated Depreciation and Deferred Credits and Other Liabilities on Generation's Consolidated Balance Sheets, was $2.7 billion and $1.4 billion, respectively. At December 31, 2002 and 2001, Generation held $3.1 billion and $3.2 billion, respectively, in trust accounts that are included as Investments in Generation's Consolidated Balance Sheets at their fair market value. Generation believes that the amounts being recovered from customers through regulated rates and earnings on nuclear decommissioning trust funds will be sufficient to fully fund its decommissioning obligations.

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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.

To account for the effects of the ICC order, in the first quarter of 2001 ComEd reduced its nuclear decommissioning regulatory asset to $372 million, reflecting the reduction in expected probable future recoveries from customers through 2006. Also, ComEd recorded an obligation to Generation of approximately $440 million representing ComEd's legal requirement to remit funds to Generation for the remaining regulatory asset amount of $372 million upon collection from customers, and for collections from customers prior to the establishment of external decommissioning trust funds in 1989 to be remitted to Generation for deposit into the decommissioning trusts through 2006. Unrealized gains and losses on decommissioning trust funds (based on the market value of the assets on the Merger date, in accordance with purchase accounting) had previously been recorded in accumulated depreciation or regulatory assets. As a result of the transfer of the ComEd nuclear plants to Generation and the ICC order limiting the regulated recoveries of decommissioning costs, net unrealized losses of $23 million (net of income taxes) at that date were reclassified to accumulated other comprehensive income. All subsequent realized gains and losses on these decommissioning trust funds' assets are based on the cost basis of the trust fund assets established on the Merger date and are reflected in Other Income and Deductions in Generation's Consolidated Statements of Income.

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 Restructuring Settlement and the Merger Settlement 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.

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 (SNF) and high-level radioactive waste. ComEd and PECO, as required by the NWPA, each signed contracts with the DOE (Standard Contract) to provide for disposal of SNF from their respective nuclear generating stations. In accordance with the NWPA and the Standard Contract, ComEd and PECO pay the DOE one mill ($.001) per kilowatt-hour 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 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 Units and its consideration of dry storage at other units.

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

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failure to honor its contractual obligation to begin disposing of SNF in January 1998. In August 2001, the Court granted ComEd's motion for partial summary judgment for liability on ComEd's breach of contract claim. In November 2001, the 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 ComEd's breach of contract claim. On August 30, 2002, after taking certain damages related to discovery, ComEd 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. This litigation was assumed by Generation in the corporate restructuring.

In July 2000, PECO entered into an agreement with the DOE relating to PECO'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. 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 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 corporate restructuring.

In November 2000, eight utilities with nuclear power plants filed a Joint Petition for Review against the DOE with the United States Court of Appeals for the Eleventh Circuit seeking to invalidate that portion of the 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. Article XVI(I) of 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 this 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. Pursuant to Article XIV(I), 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 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.

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10. Long-Term Debt

Long-term debt is comprised of the following:

		December 31, 2002
		December 31, 2002			December 31,
				Maturity Date	December 31,
		Rates		Maturity Date	2002			2001
SBG Facility		6.37%	(a)	2007	$	1,036		$	—
Senior unsecured notes		6.95%		2011		700			700
Pollution control notes, floating rates		1.23%-1.50%		2016-2034		346			317
Notes payable and other		7.25%-7.83%		2004-2020		56			9

Total Long-Term Debt(b)						2,138			1,026
	Unamortized debt discount and premium, net					(1	)		(1	)
	Due within one year					(5	)		(4	)

Long-Term Debt					$	2,132		$	1,021

(a): The rate for the SBG Facility is stated as an average rate. Under the terms of the SBG Facility, SBG is required to effectively fix the interest rate on 50% of the borrowings under the facility through its maturity in 2007. The SBG Facility is subject to a variable rate based on the LIBOR rate plus a margin of 1.375%; however, through the required interest rate swaps, SBG has effectively fixed the LIBOR component of the interest rate at 5.73% on 83% of the debt balance as of December 31, 2002.
(b): Long-term debt maturities in the period 2003 through 2007 and thereafter are as follows:

2003	$	5
2004		1
2005		—
2006		—
2007		1,036
Thereafter		1,096

Total	$	2,138

In 2002, Generation exchanged $700 million of 6.95% Senior Notes issued in 2001 for notes which are registered under the Securities Act. The exchange notes are identical to the outstanding notes except for the elimination of certain transfer restrictions and registration rights pertaining to the outstanding bonds. Generation did not receive any cash proceeds from issuance of the exchange notes.

The outstanding balance of the SBG Facility at December 31, 2002 was $1.0 billion. The SBG Facility provides that if the SBG construction projects are not completed by June 12, 2003, the SBG Facility lenders will have the right, but will not be required, to, among other things, declare all amounts then outstanding under the SBG Facility and the interest rate swap agreements to be due. Generation believes that the construction projects will be substantially complete by June 12, 2003, but that all of the approvals required under the SBG Facility may not be issued by that date. Generation is currently evaluating whether the requirements of the SBG Facility relating to the construction projects can be satisfied by June 12, 2003. In the event that the requirements are not expected to be satisfied by June 12, 2003, Generation will contact the SBG Facility lenders concerning an amendment or waiver of these provisions of the SBG Facility. Generation currently expects that arrangements for such an amendment or waiver, if necessary, can be successfully negotiated with the SBG Facility lenders.

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In May 2001, Generation entered into a forward-starting interest rate swap, with an aggregate notional amount of $500 million, to hedge the interest rate risk related to the anticipated issuance of debt. On June 11, 2001, Generation issued $700 million of senior unsecured notes with a maturity date of June 15, 2011 and an interest rate of 6.95% and closed the forward-starting interest rate swap. The aggregate loss on the settlement of the swap of $2 million, net of income taxes, was classified in Accumulated Other Comprehensive Income and is being amortized to interest expense over the life of the notes. Also during 2001, Generation issued $121 million of Pollution Control Revenue Refunding Bonds at an average variable commercial paper interest rate of 2.55% with maturities of 20 to 33 years. The proceeds from these offerings were used to refund tax-exempt debt previously issued by PECO. The use of the proceeds was accounted for as a distribution to the member.

11. Income Taxes

Income tax expense (benefit) is comprised of the following components:

		For the Year Ended December 31,
		2002			2001			2000
Included in operations:
Federal
	Current	$	67		$	253		$	177
	Deferred		123			15			(38	)
	Investment tax credit		(8	)		(8	)		(13	)
State
	Current		18			51			43
	Deferred		17			16			(9	)

		$	217		$	327		$	160

Included in cumulative effects of changes in accounting principles:
Federal
	Deferred	$	7		$	6		$	—
State
	Deferred		2			1			—

		$	9		$	7		$	—

The effective income tax rate differed from the Federal statutory rate principally due to the following:

		For the Year Ended December 31,
		2002		2001		2000
U.S. Federal statutory rate		35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	3.7		5.2		5.0
	Tax-exempt interest	(2.3	)	—		—
	Nuclear decommissioning trust income	0.9		(0.6	)	—
	Amortization of investment tax credit	(0.9	)	(0.6	)	(1.9	)
	Other	(0.5	)	—		—

Effective income tax rate		35.9	%	39.0	%	38.1	%

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The tax effect of temporary differences giving rise to Generation's deferred tax assets and liabilities are presented below:

		December 31,
		2002			2001
Deferred tax assets:
	Decommissioning and decontamination obligations	$	703		$	674
	Deferred pension and postretirement obligations		151			218
	Unrealized gains on derivative financial instruments		66			—
	Other, net		62			4

Total deferred tax assets			982			896

Deferred tax liabilities:
	Plant basis difference		(654	)		(620	)
	Deferred investment tax credit, net		(137	)		(141	)
	Unrealized gains on derivative financial instruments		—			(21	)
	Decommissioning and decontamination obligations		(96	)		(101	)
	Emission allowances		(36	)		(42	)
	Severance obligations		(7	)		—

Total deferred tax liabilities			(930	)		(925	)

Deferred income taxes (net) on the balance sheet		$	52		$	(29	)

The Internal Revenue Service and certain state tax authorities are currently auditing certain tax returns of Exelon's predecessor entities, Unicom and PECO. The current audits are not expected to have an adverse effect on financial condition or results of operations of Generation.

12. Retirement Benefits

Generation has adopted defined benefit pension plans and postretirement welfare benefit plans sponsored by Exelon. Essentially all Generation employees are eligible to participate in these plans. Benefits under these pension plans generally reflect each employee's compensation, years of service, and age at retirement.

The Pension Obligation and Non-Pension Postretirement Benefits Obligation on the Generation Consolidated Balance Sheets reflect Generation's obligations to the plan sponsor, Exelon. Employee-related assets and liabilities, including both pension and SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other than Pensions," postretirement welfare liabilities, were allocated by Exelon to its subsidiaries based on the number of active employees as of January 1, 2001 as part of Exelon's corporate restructuring. Exelon allocates the components of pension expense to the participating employers based upon several factors, including the percentage of active employees in each participating unit.

Complete pension and other postretirement benefits information for the Exelon plans are disclosed in Note 15 of the Notes to Exelon's Consolidated Financial Statements.

Approximately $37 million and $13 million were included in operating and maintenance expense in 2002 and 2001, respectively, for Generation's allocated portion of Exelon's pension and postretirement benefit expense. Generation contributed $60 million to the Exelon-sponsored plans in 2002 and did not contribute in 2001. In 2000, Generation recorded a net pension benefit of $45 million and a net postretirement benefit cost of $43 million.

Exelon's costs of providing pension and postretirement benefits are dependent upon a number of factors, such as the rates of return on pension plan assets, discount rate, and the rate of increase in

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health care costs. The market value of plan assets has been affected by sharp declines in the equity market since the third quarter of 2000. As a result, at December 31, 2002, Exelon was required to recognize an additional minimum liability as prescribed by SFAS No. 87, "Employer's Accounting for Pensions." The liability was recorded as a reduction to common 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 obligations. Based upon the market value of plan assets at December 31, 2002, the amount of the reduction to shareholders' equity (net of income taxes) is $1.0 billion. The recording of this reduction, at the Exelon holding company level, did not affect net income or cash flow in 2002 or compliance with debt covenants.

Generation participates in a 401(k) savings plan sponsored by Exelon. The plan allows employees to contribute a portion of their pretax income in accordance with specified guidelines. Generation matches a percentage of employee contributions to the plan up to certain limits. The cost of Generation's matching contributions to the savings plan totaled $31 million, $23 million and $7 million for 2002, 2001 and 2000, respectively.

13. Commitments and Contingencies

Commercial Commitments. Generation'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 and financing arrangements to secure its obligations, are as follows:

			Expiration within
	Total		2003		2004-2005		2006-2007		2008 and beyond
Credit Facility(a)	$	—	$	—	$	—	$	—	$	—
Letters of Credit (non-debt)(b)		11		6		5		—		—
Letters of Credit (Long-Term Debt)(c)		346		195		151		—		—
Performance Guarantees(d)		101		—		—		—		101
Surety Bonds(e)		43		—		—		—		43
Energy Marketing Contract Guarantees(f)		1		1		—		—		—
Nuclear Insurance Guarantee(g)		134		—		—		—		134
Sithe New England Equity Guarantee(h)		38		38		—		—		—

Total Commercial Commitments	$	674	$	240	$	156	$	—	$	278

(a): Credit Facility—Exelon, along with ComEd, PECO and Generation, maintain a $1.5 billion 364-day credit facility to support commercial paper issuances. At December 31, 2002, there were no borrowings against the credit facility. As of December 31, 2002, Generation does not have a sublimit under the facility. Additionally, at December 31, 2002, Generation did not have any commercial paper outstanding.
(b): Letters of Credit (non-debt)—Non-debt letters of credit maintained 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): Performance Guarantees—Guarantees issued to ensure execution under specific contracts.

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(e): Surety Bonds—Guarantees issued related to contract and commercial surety bonds, excluding bid bonds.
(f): Energy Marketing Contract Guarantees—Guarantees issued to ensure performance under energy commodity contracts.
(g): Nuclear Insurance Guarantee—Guarantee of nuclear insurance required under the Price-Anderson Act. This amount relates to Generation's guarantee of AmerGen's plants. Exelon has a $1.2 billion guarantee relating to Generation's directly owned plants that is not included in this amount.
(h): Sithe New England Equity Guarantee—See Note 4—Acquisitions and Dispositions for further information on the $38 million guarantee. After construction of the SBG stations is complete, Generation could be required to guarantee up to an additional $42 million in order to ensure that the SBG facilities have adequate funds available for potential outage and other operating costs and requirements.

Sithe Boston Generation Project Debt. The outstanding balance of the SBG Facility at December 31, 2002 was $1.0 billion. The SBG Facility provides that if SBG construction projects are not completed by June 12, 2003, the SBG Facility lenders will have the right, but will not be required, to, among other things, declare all amounts then outstanding under the SBG Facility and the interest rate swap agreements to be due. Generation believes that the construction projects will be substantially complete by June 12, 2003, but that all of the approvals required under the SBG Facility may not be issued by that date. Generation is currently evaluating whether the requirements of the SBG Facility relating to the construction projects can be satisfied by June 12, 2003. In the event that the requirements are not expected to be satisfied by June 12, 2003, Generation will contact the SBG Facility lenders concerning an amendment or waiver of these provisions of the SBG Facility. Generation currently expects that arrangements for such an amendment or waiver, if necessary, can be successfully negotiated with the SBG Facility lenders.

See Note 17—Unconsolidated Equity Investments for additional information about Generation's unconsolidated equity investments.

Capital Expenditures. Generation's estimated capital expenditures for 2003 are as follows:

	(in millions)
Production plant(a)	$	566
Nuclear fuel		397

Total	$	963

(a): Capital expenditures for production include expenditures to increase capacity of existing plants.

Capital Commitments. Generation and British Energy, Generation's joint venture partner in AmerGen, have each agreed to provide up to $100 million to AmerGen at any time that the Management Committee of AmerGen determines that in order to protect the public health and safety and/or to comply with NRC requirements, such funds are necessary to meet ongoing operating expenses or to safely maintain any AmerGen plant. Although Generation does not anticipate that AmerGen will make any acquisitions in 2003, Generation has committed to provide AmerGen with capital contributions equivalent to 50% of the purchase price of any acquisitions AmerGen makes in 2003.

Generation has a 70% interest in the Southeast Chicago Energy Project, LLC (Southeast Chicago), which owns a peaking facility in Chicago. Southeast Chicago is obligated to make equity distributions of $54 million over the next 20 years to the party, which is not affiliated with Generation, that owns the remaining 30% interest. This amount reflects a return of that party's investment in Southeast Chicago.

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Generation has the right to purchase, generally at a premium, and the other party has the right to require Generation to purchase, generally at a discount, the 30% interest in Southeast Chicago. Additionally, Generation may be required to purchase the 30% interest upon the occurrence of certain events, including Generation's failure to maintain an investment grade rating.

Nuclear Insurance. The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. As of January 1, 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 is a member of an industry mutual insurance company 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.

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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.

Energy Commitments. 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 maintains a net positive supply of energy and capacity, through ownership of generation assets and purchased power 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 firm commitments related to power generation of specific generation plants and/or are dispatchable in nature. Generation enters into PPAs with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to its customers. Generation has also purchased firm transmission rights to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs. The primary intent and business objective for the use of its capital assets and contracts is to provide Generation with physical power supply to enable it to deliver energy to meet customer needs. Generation primarily uses financial contracts in its wholesale marketing activities for hedging purposes. Generation also uses financial contracts to manage the risk surrounding trading for profit activities.

Generation has entered into bilateral long-term contractual obligations for sales of energy to load-serving entities, including electric utilities, municipalities, electric cooperatives, and retail load aggregators. Generation also enters into contractual obligations to deliver energy to wholesale market participants who primarily focus on the resale of energy products for delivery. Generation provides delivery of its energy to these customers through access to its transmission assets or rights for firm transmission.

Generation has PPAs with Midwest Generation, LLC (Midwest Generation) for the purchase of capacity from its coal-fired stations through 2004. Contracted capacity and capacity available through the exercise of an annual option are 1,696 MWs and 3,949 MWs in 2003 and 2004, respectively.

The agreements also provide for the option to purchase 1,084 MWs of oil and gas-fired capacity, and 857 MWs of peaking capacity, subject to reduction.

Generation has entered into PPAs with AmerGen, under which it will purchase all the energy from Unit No. 1 at Three Mile Island Nuclear Station (TMI) after December 31, 2001 through December 31, 2014. Under a January 1, 2003 PPA, Generation will purchase from AmerGen all of the residual energy from the Clinton Nuclear Power Station (Clinton), through December 31, 2003. Currently, the residual output is approximately 31% of the total output of Clinton. In accordance with the terms of the AmerGen partnership agreement, the 2003 PPA will be extended through the end of the AmerGen partnership agreement in 2006.

Generation has a long-term supply agreement through December 2022 with Distrigas of Massachusetts, LLC to guarantee physical gas supply to its New England generating units. Under the agreement, prices are indexed to New England gas markets.

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

					Power Only Purchases from
	Net Capacity Purchases(1)		Power Only Sales		Power Only Purchases from				Transmission Rights Purchases(2)
	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 Generating Station (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. 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 PECO under which PECO obtains substantially all of its electric supply from Generation 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.

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Environmental Issues. Generation's operations have in the past and may in the future require substantial capital expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, Generation is generally liable for the costs of remediating environmental contamination of property now owned and of property contaminated by hazardous substances generated by Generation.

As of December 31, 2002, Generation had accrued $15 million for environmental investigation and remediation costs. Generation cannot reasonably estimate whether it will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by Generation, environmental agencies or others, or whether such costs will be recoverable from third parties.

Leases. Minimum future operating lease payments, including lease payments for real estate and rail cars, as of December 31, 2002 were:

2003	$	32
2004		20
2005		25
2006		25
2007		26
Thereafter		464

Total minimum future lease payments	$	592

Rental expense under operating leases totaled $25 million, $29 million and $19 million for the years ended December 31, 2002, 2001 and 2000, respectively.

Litigation.

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

The United States Environmental Protection Agency (EPA) has advised Cotter that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached barium sulfate at the site. Cotter, along with three other companies identified by the EPA as potentially responsible parties (PRPs), 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.

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). Generation is also involved in the tax appeal for TMI (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.

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.

Credit Contingencies. Generation is a counterparty to Dynegy Inc. (Dynegy) in various energy transactions. In early July 2002, the credit ratings of Dynegy were downgraded by two credit rating agencies to below investment grade. As of December 31, 2002, Generation had a net receivable from Dynegy of approximately $3 million, and consistent with the terms of the existing credit arrangement, has received collateral in support of this receivable. Generation also has credit risk associated with Dynegy through Generation's equity investment in Sithe. Sithe is a 60% owner of the Independence generating station (Independence), a 1,040-MW gas-fired qualified facility that has an energy-only long-term tolling agreement with Dynegy, with a related financial swap arrangement. As of December 31, 2002, Sithe had recognized an asset on its balance sheet related to the fair market value of the financial swap agreement with Dynegy that is marked to market under the terms of SFAS No. 133. If Dynegy is unable to fulfill the terms of this agreement, Sithe would be required to impair this financial swap asset. Generation estimates, as a 49.9% owner of Sithe, that the impairment would result in an after-tax reduction of its earnings of approximately $10 million.

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In addition to the impairment of the financial swap asset, if Dynegy was unable to fulfill its obligations under the financial swap agreement and the tolling agreement, Generation would likely incur a further impairment associated with Independence. Depending upon the timing of Dynegy's failure to fulfill its obligations and the outcome of any restructuring initiatives, Generation could realize an after-tax charge of between $0 and $130 million. In the event of a sale of Generation's investment in Sithe to a third party, proceeds from the sale could be negatively impacted between $65 million to $100 million (after-tax).

Additionally, the future economic value of AmerGen's PPA with Illinois Power, a subsidiary of Dynegy, could be impacted by events related to Dynegy's financial condition.

14. Fair Value of Financial Assets and Liabilities

The carrying amounts and fair values of Generation's financial assets and liabilities as of December 31 were as follows:

		2002						2001
		Carrying Amount			Fair Value			Carrying Amount		Fair Value
Non-derivatives:
Assets:
	Nuclear decommissioning trust funds	$	3,053		$	3,053		$	3,165	$	3,165
Liabilities:
	Long-term debt (including amounts due within one year)	$	2,137		$	2,199		$	1,025	$	1,040
Derivatives:
	Energy derivatives	$	(163	)	$	(163	)	$	92	$	92

As of December 31, 2002 and 2001, Generation's carrying amounts of cash and cash equivalents and accounts receivable are representative of fair value because of the short-term nature of these instruments. Fair values of the trust accounts for decommissioning nuclear plants and long-term debt are estimated based on quoted market prices for the same or similar issues. The fair value of Generation's interest rate swaps and purchased power and sale contracts is determined using quoted exchange prices, external dealer prices, or internal valuation models which utilize assumptions of future energy prices and available market pricing curves.

Financial instruments that potentially subject Generation to concentrations of credit risk consist principally of cash equivalents and customer accounts receivable. Generation places its cash equivalents with high-credit quality financial institutions. Generally, such investments are in excess of the Federal Deposit Insurance Corporation limits.

Under the terms of the SBG Facility, SBG is required to effectively fix the interest rate on 50% of the borrowings under the facility through its maturity in 2007. As of December 31, 2002, Generation has entered into floating to fixed interest rate swap agreements that have effectively fixed the interest rate on $861 million of notional principal, or 83% of borrowings outstanding under the SBG Facility at December 31, 2002. These swaps have been designated as cash flow hedges under SFAS No. 133, and as such, as long as the hedge remains effective and the underlying transaction remains probable, changes in the fair value of these swaps will be recorded in accumulated other comprehensive income until earnings are affected by the variability of the cash flows being hedged. The fair market value exposure of these swaps was $92 million at December 31, 2002. Generation utilizes derivatives to manage the utilization of its available generating capacity and provision of wholesale energy to its affiliates. Generation also utilizes energy option contracts and energy financial swap arrangements to limit the market price risk associated with forward energy commodity contracts. Additionally, Generation enters into certain energy-related derivatives for trading or speculative purposes.

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During 2002 and 2001, Generation recognized net gains of $6 million ($4 million, net of income taxes) and gains of $16 million ($10 million, net of income taxes), respectively, relating to mark-to-market adjustments of certain non-trading purchased power and sale contracts pursuant to SFAS No. 133. Mark-to-market adjustments on non-trading purchased power and sale contracts are reported in purchased power and fuel and mark-to-market adjustments on trading activities are reported as Operating Revenues in the Consolidated Statements of Income. During 2002 and 2001, Generation recognized net losses aggregating $9 million ($6 million, net of income taxes) and net gains aggregating $14 million ($10 million, net of income taxes), respectively, relating to mark-to-market adjustments on derivative instruments entered into for trading purposes. Generation commenced financial trading in the second quarter of 2001. Gains and losses associated with financial trading are reported as Operating Revenue in the Consolidated Statements of Income. During 2002 and 2001, no amounts were reclassified from accumulated other comprehensive income into earnings as a result of forecasted energy commodity transactions no longer being probable. For 2002, no amounts were reclassified from accumulated other comprehensive income into earnings as a result of forecasted financing transactions no longer being probable. For 2001, a $6 million gain ($4 million, net of income taxes) was reclassified from accumulated other comprehensive income into earnings as a result of forecasted financing transactions no longer being probable.

On January 1, 2001, Generation recognized a non-cash gain of $12 million, net of income taxes, in earnings and deferred a non-cash gain of $5 million, net of income taxes, in accumulated other comprehensive income, a component of member's equity, to reflect the initial adoption of SFAS No. 133, as amended. SFAS No. 133 must be applied to all derivative instruments and requires that such instruments be recorded in the balance sheet either as an asset or a liability measured at their fair value through earnings, with special accounting permitted for certain qualifying hedges. As of December 31, 2002, approximately $124 million of deferred net losses on derivative instruments accumulated in other comprehensive income are expected to be reclassified to earnings during the next twelve months. Amounts in accumulated other comprehensive income related to interest rate cash flows are reclassified into earnings when the forecasted interest payment occurs. Amounts in accumulated other comprehensive income related to energy commodity cash flows are reclassified into earnings when the forecasted purchase or sale of the energy commodity occurs. The majority of Generation's cash flow hedges are expected to settle within the next 3 years.

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Generation classifies investments in the trust accounts for decommissioning nuclear plants as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in these trust accounts.

				December 31, 2002
		Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
Equity securities		$	1,763	$	72	$	(482	)	$	1,353
Debt securities
	Government obligations		938		62					1,000
	Other debt securities		698		32		(30	)		700

Total debt securities			1,636		94		(30	)		1,700

Total available-for-sale securities		$	3,399	$	166	$	(512	)	$	3,053

				December 31, 2001
		Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
Equity securities		$	1,666	$	130	$	(236	)	$	1,560
Debt securities
	Government obligations		882		28		(3	)		907
	Other debt securities		701		16		(19	)		698

Total debt securities			1,583		44		(22	)		1,605

Total available-for-sale securities		$	3,249	$	174	$	(258	)	$	3,165

Net unrealized losses of $346 million and $84 million were recognized in Accumulated Depreciation and Other Comprehensive Income in Generation's Consolidated Balance Sheets at December 31, 2002 and 2001, respectively.

	2002			2001
Proceeds from sales	$	1,612		$	1,624
Gross realized gains		56			76
Gross realized losses		(86	)		(189	)

�� Net realized gains of $2 million and $14 million were recognized in Accumulated Depreciation in Generation's Consolidated Balance Sheets at December 31, 2002 and 2001, respectively, and $32 million and $127 million of net realized losses were recognized in Other Income and Deductions in Generation's Consolidated Income Statements for 2002 and 2001, respectively. The available-for-sale securities held at December 31, 2002 have an average maturity of six to seven years. The cost of these securities was determined on the basis of specific identification. See Note 9—Nuclear Decommissioning and Spent Fuel Storage for further information regarding the nuclear decommissioning trusts.

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15. Quarterly Data (Unaudited)

The data shown below include all adjustments which Generation considers necessary for a fair presentation of such amounts:

	Operating Revenues				Operating Income				Income (Loss) Before Cumulative Effect of a Change in Accounting Principle				Net Income
	2002		2001		2002		2001		2002		2001		2002		2001
Quarter ended:
March 31	$	1,461	$	1,628	$	89	$	268	$	66	$	158	$	79	$	170
June 30		1,559		1,583		113		113		84		71		84		71
September 30		2,212		2,193		186		225		163		140		163		140
December 31		1,626		1,422		121		266		74		143		74		143

16. Related-Party Transactions

Generation's financial statements include related-party transactions as reflected in the tables below.

		For the Years Ended December 31,
		2002		2001		2000
Operating Revenues from Affiliates
	ComEd(1)	$	2,542	$	2,657	$	403
	PECO(1)		1,438		1,162		871
	Exelon Energy(2)		247		284		277
Purchased Power from Affiliates
	AmerGen(3)		273		57		52
	ComEd(4)		20		28		—
	PECO(4)		3		6		—
	Exelon Energy(4)		18		91		—
O&M from Affiliates
	Sithe(5)		13		—		—
	ComEd(4)		14		12		—
	PECO(4)		9		6		—
	BSC(17)		116		110		46
Interest Expense from Affiliates
	Sithe(11)		2		—		—
	Exelon(6,7)		5		23		2
	ComEd(9)		—		9		—
	PECO(8)		—		6		—
Interest Income from Affiliates
	AmerGen(10)		2		—		—
	Sithe(18)		—		2		—
	ComEd(12,13)		4		10		—
Services Provided to Affiliates
	AmerGen(14)		70		80		32
	Sithe(15)		1		—		—

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		December 31,
		2002		2001
Receivables from Affiliates
	ComEd(1,4,9)	$	339	$	136
	ComEd Decommissioning(16)		59		59
	AmerGen(3,10)		39		44
	PECO(1)		124		117
	BSC(17)		14		28
	Exelon Energy(2)		19		17
Long-Term Receivable from Affiliate
	Generation decommissioning obligation(16)		218		291
	Other		2		—
Payables to Affiliates
	Sithe(5)		7		—
	Exelon(7)		3		23
	BSC(17)		—		11
Notes Payable to Affiliates
	Exelon(6)		329		—
	Sithe(11)		534		—

(1): Effective January 1, 2001, Generation entered into PPAs with ComEd and PECO. See Note 13—Commitments and Contingencies for further information on the PPAs.
(2): Generation sells power to Exelon Energy.
(3): Generation has entered into PPAs dated December 18, 2001 and November 22, 1999 with AmerGen. Under the 2001 PPA, Generation has agreed to purchase from AmerGen all the energy from Unit No. 1 at Three Mile Island Nuclear Station from January 1, 2002 through December 31, 2014. Under the 1999 PPA, Generation agreed to purchase from AmerGen all of the residual energy from Clinton Nuclear Power Station (Clinton), through December 31, 2002. Currently, the residual output is approximately 31% of the total output of Clinton. In accordance with the terms of the AmerGen partnership agreement, the 1999 PPA will be extended through the end of the AmerGen partnership agreement in 2006.
(4): Generation purchases power from AmerGen under PPAs as discussed in the above section of this note. Additionally, Generation purchases power from PECO for Generation's own use, buys back excess power from Exelon Energy and purchases transmission and ancillary services from ComEd.
(5): Under a service agreement dated December 18, 2000, Sithe provides Generation certain fuel and project development services. Sithe is compensated for these services in the amount agreed to in the work order, but not less than the higher of fully allocated costs for performing such services or the market price.
(6): Generation had a $329 million payable to Exelon at December 31, 2002, related to the acquisition of two generating plants in April of 2002.
(7): In relation to the December 18, 2000 acquisition of 49.9% of Sithe common stock, Generation had a $700 million payable to Exelon, which was repaid in the second quarter of 2001.
(8): Generation paid interest to PECO in 2001 related to a loan.
(9): In order to facilitate payment processing, ComEd processes certain invoice payments on behalf of Generation.

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(10): In February 2002, Generation entered into an agreement to loan AmerGen up to $75 million at an interest rate equal to the 1-month London Interbank Offering Rate plus 2.25%. In July 2002, the limit of the loan agreement was increased to $100 million and the maturity date was extended to July 1, 2003. As of December 31 2002, the outstanding principal balance of the loan was $35 million.
(11): Under the terms of the agreement to acquire Sithe New England dated November 1, 2002, Generation issued a $534 million note to be paid in full on June 18, 2003 to Sithe. The note bears interest at the rate equal to LIBOR plus 0.875%. Interest accrued on the note as of December 31, 2002 was $2 million.
(12): In consideration for the net assets transferred as a part of the corporate restructuring effective January 1, 2001, Generation had a note receivable from ComEd. This note was repaid in 2001.
(13): Interest income for 2002 is related to unpaid ComEd PPA billings.
(14): Under a service agreement dated March 1, 1999, Generation provides AmerGen with certain operation and support services to the nuclear facilities owned by AmerGen. This service agreement has an indefinite term and may be terminated by Generation or AmerGen with 90 days notice. Generation is compensated for these services in an amount agreed to in the work order, which is not less than the higher of its fully allocated cost for performing each service or the market price for such service.
(15): Under a service agreement dated December 18, 2000, Generation provides certain engineering and environmental services for fossil facilities owned by Sithe and for certain developmental projects. Generation is compensated for these services in an amount agreed to in the work order, but not less than the higher of fully allocated costs for performing such services or the market price.
(16): Generation had a short-term and a long-term receivable from ComEd, primarily representing ComEd's legal requirements to remit collections of nuclear decommissioning costs from customers to Generation resulting from the 2001 corporate restructuring.
(17): Generation receives a variety of corporate support services from BSC, including legal, human resources, financial and information technology services. Such services are provided at cost, including applicable overhead. Some third party reimbursements due Generation are recovered through BSC.
(18): In August 2001, Exelon loaned Sithe, an equity method investee of Generation, $150 million. The note, which bore interest at the eurodollar rate, plus 2.25%, was repaid in December 2001 with the proceeds of bank borrowings. In connection with the bank borrowings, Exelon provided the lender with a support letter confirming its investment in Sithe and Exelon's agreement to maintain a positive net worth of Sithe.

17. Unconsolidated Equity Investments

Sithe Energies, Inc. Generation is a 49.9% owner of Sithe and accounts for the investment as an unconsolidated equity investment. The Sithe New England asset purchase did not affect the accounting for Sithe as an equity investment. Separate from the Sithe New England transaction, 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. At the end of this exercise period, which is December 2005, if Generation has not exercised its Call option and the other stockholders have not exercised their Put rights, Generation will have an additional one-time option to purchase

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shares from the other stockholders to bring Generation's ownership in Sithe from the current 49.9% to 50.1% of Sithe's total outstanding common stock.

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, the 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 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 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 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.

Additionally, the debt on the books of Generation's unconsolidated equity investments and joint ventures is not reflected on its Consolidated Balance Sheets. Generation estimates that this debt, including, Sithe's debt described in the preceding paragraph, totals approximately $1.3 billion and that Generation's portion of that amount, based on its ownership interest in the investments, is approximately $673 million.

AmerGen Energy Company, LLC. Generation and British Energy each own a 50% equity interest in AmerGen. Established in 1997, AmerGen was formed to pursue opportunities to acquire and operate nuclear generation facilities in the North America. Currently, AmerGen owns and operates three nuclear generation facilities: Clinton located in Illinois, TMI located in Pennsylvania, and Oyster Creek, which was acquired in August 2000, located in New Jersey. Oyster Creek was acquired from GPU, Inc. (GPU) for $10 million. Under the terms of the purchase agreement, GPU agreed to fund outage costs of $89 million, including the cost of fuel, for a refueling outage that occurred in 2000.

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AmerGen is repaying these costs to GPU in equal annual installments through 2009. In addition, AmerGen assumed full responsibility for the ultimate decommissioning of Oyster Creek. At the closing of the sale, GPU provided funding for the decommissioning trust of $440 million. In conjunction with this acquisition, AmerGen has received a fully funded decommissioning trust fund which has been computed assuming the anticipated costs to appropriately decommission Oyster Creek discounted to net present value using the NRC's mandated rate of 2%. The agreement with the seller for Clinton calls for Generation to sell 75% of the output back to Illinois Power for a term expiring at the end of 2004. The agreement with the seller for all output of Oyster Creek expires March 2003. The agreement between Generation and TMI for all output expires December 2014.

AmerGen maintains a nuclear decommissioning trust fund for each of its plants in accordance with NRC regulations and believes that amounts in these trust funds, together with the investment earnings thereon and additional contributions for Clinton from Illinois Power, will be sufficient to meet its decommissioning obligations.

Generation's investment in AmerGen as of December 31, 2002 and 2001 was $160 million and $95 million, respectively. Generation and British Energy have each agreed to provide up to $100 million to AmerGen at any time that the Management Committee of AmerGen determines that, in order to protect the public health and safety and/or to comply with NRC requirements, these funds are necessary to meet ongoing operating expenses or to safely maintain any AmerGen plant. The current financial condition of British Energy has been the focus of media attention recently. Generation cannot predict the ability of British Energy to provide funds to AmerGen. However, we do not believe this will impact AmerGen's ability to conduct its business.

The table below presents summarized financial information for AmerGen:

	For the Years Ended December 31,
	2002		2001		2000
Income Statement Information
Operating revenues	$	644	$	602	$	450
Operating income		124		122		9
Income before cumulative effect of change in accounting principle		117		156		(5	)
Net Income		161		156		(5	)

	December 31,
	2002			2001
Balance Sheet Information
Current assets	$	89		$	115
Noncurrent assets		1,490			1,394

Total assets	$	1,579		$	1,509

Current liabilities	$	148		$	184
Noncurrent liabilities		1,112			1,126
Members' capital		80			80
Additional paid-in capital		—			—
Retained earnings		316			155
Accumulated other comprehensive income (loss)		(77	)		(36	)

Total capitalization and liabilities	$	1,579		$	1,509

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The table below presents summarized financial information for Sithe:

	For the Years Ended December 31,
	2002			2001			2000
Income Statement Information
Operating revenues	$	1,031		$	1,090		$	1,226
Operating income		170			175			537
Net Income		(348	)		(164	)		260

	December 31,
	2002			2001
Balance Sheet Information
Current assets	$	1,145		$	508
Noncurrent assets		1,427			3,515

Total assets	$	2,572		$	4,023

Current liabilities	$	256		$	407
Noncurrent liabilities		1,509			2,513
Additional paid-in capital		735			735
Retained earnings		89			437
Accumulated other comprehensive income (loss)		(17	)		(69	)

Total capitalization and liabilities	$	2,572		$	4,023

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Exelon, ComEd, PECO and Generation

None.

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Exelon

The information required by Item 10 relating to directors and nominees for election as directors at Exelon's Annual Meeting of shareholders is incorporated herein by reference to the information under the heading "BOARD OF DIRECTORS" on pages 12-14 in Exelon's definitive Proxy Statement (2003 Exelon Proxy Statement) filed with the SEC on March 13, 2003, pursuant to Regulation 14A under the Securities Exchange Act of 1934. The information required by Item 10 relating to executive officers is set forth above in ITEM 1. Business—Executive Officers of Exelon, ComEd, PECO and Generation.

ComEd

The information required by Item 10 relating to directors and nominees for election as directors at ComEd's annual meeting of shareholders is incorporated herein by reference to information under the subheadings "Nominees" and "Security Ownership of Certain Beneficial Owners and Management" under the heading "Election of Directors" in ComEd's definitive Information Statement (2003 ComEd Information Statement) to be filed with the SEC prior to April 30, 2003, pursuant to Regulation 14C under the Securities Exchange Act of 1934. The information required by Item 10 relating to executive officers is set forth above in ITEM 1. Business—Executive Officers of Exelon, ComEd, PECO and Generation.

PECO

The information required by Item 10 relating to directors and nominees for election as directors at PECO's annual meeting of shareholders is incorporated herein by reference to information under the subheadings "Nominees" and "Security Ownership of Certain Beneficial Owners and Management" under the heading "Election of Directors" in PECO's definitive Information Statement (2003 PECO Information Statement) to be filed with the SEC prior to April 30, 2003, pursuant to Regulation 14C under the Securities Exchange Act of 1934. The information required by Item 10 relating to executive officers is set forth above in ITEM 1. Business—Executive Officers of Exelon, ComEd, PECO and Generation.

ITEM 11. EXECUTIVE COMPENSATION

Exelon

The information required by Item 11 is incorporated herein by reference to the information labeled "Executive Compensation" on pages 24-36 and "Board Compensation" on page 18 in the 2003 Exelon Proxy Statement.

ComEd

The information required by Item 11 is incorporated herein by reference to the paragraph labeled "Board Compensation" and the paragraphs under the heading "Executive Compensation" (other than the paragraphs under the subheading "Compensation Committee Report on Executive Compensation") in the 2003 ComEd Information Statement.

PECO

The information required by Item 11 is incorporated herein by reference to the paragraph labeled "Board Compensation" and the paragraphs under the heading "Executive Compensation" (other than

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the paragraphs under the subheading "Compensation Committee Report on Executive Compensation") in the 2003 PECO Information Statement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Exelon

The information required by Item 12 relating to security ownership of certain beneficial owners and management is incorporated herein by reference to the stock ownership information under the heading "BENEFICIAL OWNERSHIP" on pages 10-11 in the 2003 Exelon Proxy Statement.

Securities Authorized for Issuance under Equity Compensation Plans

Plan Category	Number of securities to be issued upon exercise of outstanding options	Weighted-average price of outstanding options		Number of securities remaining available for future issuance under equity compensation plans(a)
Equity compensation plans approved by security holders	14,782,309	$	46.14	13,478,026
Equity Compensation plans not approved by security holders	1,104,681		41.09	—

Total	15,886,990	$	45.80	13,478,026

(a): Excludes securities to be issued upon exercise of outstanding options.

ComEd

The information required by Item 12 relating to security ownership of certain beneficial owners and management is incorporated herein by reference to the stock ownership information under the heading "Beneficial Ownership" in the 2003 ComEd Information Statement.

Securities Authorized for Issuance under Equity Compensation Plans: none

PECO

The information required by Item 12 relating to security ownership of certain beneficial owners and management is incorporated herein by reference to the stock ownership information under the heading "Beneficial Ownership" in the 2003 PECO Information Statement.

Securities Authorized for Issuance under Equity Compensation Plans: none

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Exelon

The information required by Item 13 is incorporated herein by reference to the information labeled "OTHER INFORMATION—Transactions with Management" on pages 39-40 in the 2003 Exelon Proxy Statement.

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ComEd

The information required by Item 13 is incorporated herein by reference to the information under the subheading "Transactions with Management" under the heading "Other Information" in the 2003 ComEd Information Statement.

PECO

None.

ITEM 14. CONTROLS AND PROCEDURES

Exelon

Within the 90 days prior to the date of this Report, Exelon's management, including the principal executive officer and principal financial officer, evaluated Exelon's disclosure controls and procedures related to the recording, processing, summarization and reporting of information in Exelon's periodic reports that it files with the Securities and Exchange Commission (SEC). These disclosure controls and procedures have been designed to ensure that (a) material information relating to Exelon, including its consolidated subsidiaries, is made known to Exelon's management, including these officers, by other employees of Exelon and its subsidiaries, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC's rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people. Exelon's controls and procedures can only provide reasonable, not absolute, assurance that the above objectives have been met. Also, Exelon does not control or manage certain of its unconsolidated entities and as such, the disclosure controls and procedures with respect to such entities are more limited than those it maintains with respect to its consolidated subsidiaries.

As of the date of their evaluation, these officers concluded that, subject to limitations noted above, the design of the disclosure controls and procedures provide reasonable assurance that they can accomplish their objectives. Exelon continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant.

There have been no significant changes in Exelon's internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

ComEd

Within the 90 days prior to the date of this Report, ComEd's management, including the principal executive officer and principal financial officer, evaluated ComEd's disclosure controls and procedures related to the recording, processing, summarization and reporting of information in ComEd's periodic reports that it files with the Securities and Exchange Commission (SEC). These disclosure controls and procedures have been designed to ensure that (a) material information relating to ComEd, including its consolidated subsidiaries, is made known to ComEd's management, including these officers, by other employees of ComEd and its subsidiaries, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC's rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people. ComEd's controls and

259

procedures can only provide reasonable, not absolute, assurance that the above objectives have been met. Also, ComEd does not control or manage certain of its unconsolidated entities and as such, the disclosure controls and procedures with respect to such entities are more limited than those it maintains with respect to its consolidated subsidiaries.

As of the date of their evaluation, these officers concluded that, subject to limitations noted above, the design of the disclosure controls and procedures provide reasonable assurance that they can accomplish their objectives. ComEd continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant.

There have been no significant changes in ComEd's internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

PECO

Within the 90 days prior to the date of this Report, PECO's management, including the principal executive officer and principal financial officer, evaluated PECO's disclosure controls and procedures related to the recording, processing, summarization and reporting of information in PECO's periodic reports that it files with the Securities and Exchange Commission (SEC). These disclosure controls and procedures have been designed to ensure that (a) material information relating to PECO, including its consolidated subsidiaries, is made known to PECO's management, including these officers, by other employees of PECO and its subsidiaries, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC's rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people. PECO's controls and procedures can only provide reasonable, not absolute, assurance that the above objectives have been met. Also, PECO does not control or manage certain of its unconsolidated entities and as such, the disclosure controls and procedures with respect to such entities are more limited than those it maintains with respect to its consolidated subsidiaries.

As of the date of their evaluation, these officers concluded that, subject to limitations noted above, the design of the disclosure controls and procedures provide reasonable assurance that they can accomplish their objectives. PECO continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant.

There have been no significant changes in PECO's internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

Generation

Within the 90 days prior to the date of this Report, Generation's management, including the principal executive officer and principal financial officer, evaluated Generation's disclosure controls and procedures related to the recording, processing, summarization and reporting of information in Generation's periodic reports that it files with the Securities and Exchange Commission (SEC). These disclosure controls and procedures have been designed to ensure that (a) material information relating to Generation, including its consolidated subsidiaries, is made known to Generation's management, including these officers, by other employees of Generation and its subsidiaries, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC's rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in

260

decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people. Generation's controls and procedures can only provide reasonable, not absolute, assurance that the above objectives have been met. Also, Generation does not control or manage certain of its unconsolidated entities and as such, the disclosure controls and procedures with respect to such entities are more limited than those it maintains with respect to its consolidated subsidiaries.

As of the date of their evaluation, these officers concluded that, subject to limitations noted above, the design of the disclosure controls and procedures provide reasonable assurance that they can accomplish their objectives. Generation continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant.

There have been no significant changes in Generation's internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

261

PART IV

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

Report of Independent Accountants on
Financial Statement Schedule

To the Shareholders and Board of Directors
of Exelon Corporation:

Our audits of the consolidated financial statements referred to in our report dated January 29, 2003, except for Note 23 for which the date is February 20, 2003, appearing in the 2002 Annual Report to Shareholders of Exelon Corporation (which report and consolidated financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 15(a)(1)(ii) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

PricewaterhouseCoopers LLP

Chicago, Illinois
January 29, 2003

262

(a)

Financial Statements and Financial Statement Schedules

(1)

Exelon

(i): Financial Statements

		Consolidated Statements of Income for the years 2002, 2001 and 2000
		Consolidated Statements of Cash Flows for the years 2002, 2001 and 2000
		Consolidated Balance Sheets as of December 31, 2002 and 2001
		Consolidated Statements of Changes in Shareholders' Equity for the years 2002, 2001 and 2000
		Consolidated Statements of Comprehensive Income for the years 2002, 2001 and 2000
		Notes to Consolidated Financial Statements

(ii): Financial Statement Schedule

263

EXELON CORPORATION AND SUBSIDIARY COMPANIES

Schedule II—Valuation and Qualifying Accounts
(in millions)

Column A	Column B		Column C					Column D			Column E
			Additions
Description	Balance at Beginning of Year		Charged to Cost and Expenses		Charged to Other Accounts			Deductions			Balance at End of Year
For The Year Ended December 31, 2002
Allowance for Uncollectible Accounts	$	213	$	129	$	—		$	210	(a)	$	132
Reserve for:
Merger-Related Costs	$	114	$	—	$	(12	)	$	74		$	28
Injuries and Damages	$	72	$	42	$	10		$	25	(b)	$	99
Environmental Investigation and Remediation	$	156	$	21	$	12		$	33	(c)	$	156
Obsolete Materials	$	18	$	9	$	4		$	13		$	18
For The Year Ended December 31, 2001
Allowance for Uncollectible Accounts	$	200	$	145	$	—		$	132	(a)	$	213
Reserve for:
Merger-Related Costs	$	144	$	—	$	41		$	71		$	114
Injuries and Damages	$	69	$	17	$	2		$	16	(b)	$	72
Environmental Investigation and Remediation	$	171	$	1	$	—		$	16	(c)	$	156
Obsolete Materials	$	103	$	16	$	—		$	101		$	18
For The Year Ended December 31, 2000
Allowance for Uncollectible Accounts	$	112	$	87	$	59	(d)	$	58	(a)	$	200
Reserve for:
Merger-Related Costs	$	—	$	—	$	149	(e)	$	5		$	144
Injuries and Damages	$	23	$	9	$	48	(f)	$	11	(b)	$	69
Environmental Investigation and Remediation	$	57	$	26	$	98	(e)	$	10	(c)	$	171
Obsolete Materials	$	—	$	48	$	55	(e)	$	—		$	103

(a): Write-off of individual accounts receivable.
(b): Payments of claims and related costs.
(c): Expenditures for site investigation and remediation.
(d): Includes October 20, 2000 opening balance of former Unicom Corporation of $48 million.
(e): Reflects October 20, 2000 opening balance of former Unicom Corporation.
(f): Reflects October 20, 2000 opening balance of former Unicom Corporation of $47 million.

264

(2)

ComEd

(i): Financial Statements

		Consolidated Statements of Income for the years 2002 and 2001, and the periods from October 20, 2000 to December 31, 2000 and from January 1, 2000 to October 19, 2000
		Consolidated Statements of Cash Flows for the years 2002 and 2001, and the periods from October 20, 2000 to December 31, 2000 and from January 1, 2000 to October 19, 2000
		Consolidated Balance Sheets as of December 31, 2002 and 2001
		Consolidated Statements of Changes in Shareholders' Equity for the years 2002 and 2001, and the periods from October 20, 2000 to December 31, 2000 and from January 1, 2000 to October 19, 2000
		Consolidated Statements of Comprehensive Income for the years 2002 and 2001, and the periods from October 20, 2000 to December 31, 2000 and from January 1, 2000 to October 19, 2000
		Notes to Consolidated Financial Statements

(ii): Financial Statement Schedule

265

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

Schedule II—Valuation and Qualifying Accounts
(in millions)

Column A	Column B		Column C					Column D			Column E		Column F
			Additions and adjustments
Description	Balance at Beginning of Year		Charged to Cost and Expenses		Charged to Other Accounts			Deductions			Restructuring Transfers(a)		Balance at End of Year
For The Year Ended December 31, 2002
Allowance for Uncollectible Accounts	$	49	$	50	$	—		$	75		$	—	$	24
Reserve for: Merger-Related Costs	$	63	$	—	$	(9	)	$	41		$	—	$	13
Injuries and Damages	$	37	$	23	$	—		$	14	(b)	$	—	$	46
Environmental Investigation and Remediation	$	105	$	19	$	—		$	23	(c)	$	—	$	101
Obsolete Materials	$	6	$	—	$	—		$	1		$	—	$	5
For The Year Ended December 31, 2001
Allowance for Uncollectible Accounts	$	60	$	42	$	1		$	54		$	—	$	49
Reserve for: Merger-Related Costs	$	144	$	—	$	25		$	29		$	77	$	63
Injuries and Damages	$	48	$	4	$	—		$	7	(b)	$	8	$	37
Environmental Investigation and Remediation	$	117	$	1	$	—		$	13	(c)	$	—	$	105
Obsolete Materials	$	98	$	—	$	—		$	14		$	78	$	6
For The Year Ended December 31, 2000
Allowance for Uncollectible Accounts	$	49	$	46	$	11		$	46		$	—	$	60
Reserve for: Merger-Related Costs	$	—	$	—	$	149		$	5		$	—	$	144
Injuries and Damages	$	55	$	10	$	5		$	22	(b)	$	—	$	48
Environmental Investigation and Remediation	$	100	$	26	$	—		$	9	(c)	$	—	$	117
Obsolete Materials	$	27	$	57	$	19		$	5		$	—	$	98

(a): Represents amounts transferred as part of the 2001 Corporate Restructuring. See ITEM 8. Financial Statements and Supplementary Information—ComEd—Note 2—Corporate Restructuring of Notes to Consolidated Financial Statements.
(b): Payments of claims and related costs.
(c): Expenditures for site investigation and remediation.

266

(3)

PECO

(i): Financial Statements

		Consolidated Statements of Income for the years 2002, 2001 and 2000
		Consolidated Statements of Cash Flows for the years 2002, 2001 and 2000
		Consolidated Balance Sheets as of December 31, 2002 and 2001
		Consolidated Statements of Changes in Shareholders' Equity for the years 2002, 2001 and 2000
		Consolidated Statements of Comprehensive Income for the years 2002, 2001 and 2000
		Notes to Consolidated Financial Statements

(ii): Financial Statement Schedule

267

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

Schedule II—Valuation and Qualifying Accounts
(in millions)

	Column A		Column B		Column C		Column D			Column E		Column F
			Additions and adjustments
Description	Balance at Beginning of Year		Charged to Cost and Expenses		Charged to Other Accounts		Deductions			Restructuring Transfers(a)		Balance at End of Year
For The Year Ended December 31, 2002
Allowance for Uncollectible Accounts	$	110	$	45	$	—	$	83	(b)	$	—	$	72
Reserve for:
Injuries and Damages	$	25	$	10	$	—	$	11	(c)	$	—	$	24
Environmental Investigation and Remediation	$	37	$	3	$	6	$	6	(d)	$	—	$	40
Obsolete Materials	$	1	$	—	$	—	$	1		$	—	$	—
For The Year Ended December 31, 2001
Allowance for Uncollectible Accounts	$	131	$	69	$	—	$	67	(b)	$	23	$	110
Reserve for:
Injuries and Damages	$	21	$	13	$	—	$	9	(c)	$	—	$	25
Environmental Investigation and Remediation	$	54	$	—	$	—	$	2	(d)	$	15	$	37
Obsolete Materials	$	3	$	6	$	—	$	7		$	1	$	1
For The Year Ended December 31, 2000
Allowance for Uncollectible Accounts	$	112	$	68	$	—	$	49	(b)	$	—	$	131
Reserve for:
Injuries and Damages	$	23	$	7	$	—	$	9	(c)	$	—	$	21
Environmental Investigation and Remediation	$	57	$	—	$	—	$	3	(d)	$	—	$	54

(a): Represents amounts transferred as part of the 2001 Corporate Restructuring. See ITEM 8. Financial Statements and Supplementary Information—PECO—Note 2—Corporate Restructuring of Notes to the Consolidated Financial Statements.
(b): Write-off of individual accounts receivable.
(c): Payments of claims and related costs.
(d): Expenditures for site investigation and remediation.

268

(4): Generation
(i): Financial Statements

Consolidated Statements of Income for the years 2002, 2001 and 2000

Consolidated Statements of Cash Flow for the years 2002, 2001 and 2000

Consolidated Balance Sheets as of December 31, 2002 and 2001

Consolidated Statements of Changes in Divisional/Member's Equity for the years 2002, 2001 and 2000

Consolidated Statements of Comprehensive Income for the years 2002, 2001 and 2000

Notes to Consolidated Financial Statements

(ii): Financial Statement Schedule

269

EXELON GENERATION COMPANY AND SUBSIDIARY COMPANIES

Schedule II—Valuation and Qualifying Accounts
(in millions)

	Column A		Column B		Column C			Column D			Column E		Column F
			Additions and adjustments
Description	Balance at Beginning of Year		Charged to Cost and Expenses		Charged to Other Accounts			Deductions			Merger Transfer(a)		Balance at End of Year
For The Year Ended December 31, 2002
Allowance for Uncollectible Accounts	$	17	$	26	$	—		$	21	(b)	$	—	$	22
Reserve for:
Merger Related Costs	$	31	$	—	$	(2	)	$	22	(c)	$	—	$	7
Injuries and Damages	$	12	$	25	$	—		$	9		$	—	$	28
Environmental Investigation and Remediation	$	14	$	—	$	7	(e)	$	6	(d)	$	—	$	15
Obsolete Materials	$	12	$	10	$	3		$	12		$	—	$	13
For The Year Ended December 31, 2001
Allowance for Uncollectible Accounts	$	2	$	16	$	—		$	1	(b)	$	—	$	17
Reserve for:
Merger Related Costs	$	50	$	—	$	(10	)	$	9		$	—	$	31
Injuries and Damages	$	8	$	—	$	4		$	—		$	—	$	12
Environmental Investigation and Remediation	$	15	$	—	$	—		$	1	(d)	$	—	$	14
Obsolete Materials	$	79	$	11	$	—		$	78		$	—	$	12
For The Year Ended December 31, 2000
Allowance for Uncollectible Accounts	$	—	$	2	$	—		$	—	(b)	$	—	$	2
Reserve for:
Merger Related Costs	$	—	$	—	$	—		$	—		$	50	$	50
Injuries and Damages	$	—	$	—	$	8		$	—	(c)	$	—	$	8
Environmental Investigation and Remediation	$	16	$	—	$	—		$	1	(d)	$	—	$	15
Obsolete Materials	$	1	$	—	$	78		$	—		$	—	$	79

(a): Represents amounts transferred as part of the Merger. See ITEM 8. Financial Statements and Supplementary Information—Generation—Note 2—Merger of the Notes to Consolidated Financial Statements.
(b): Write-off of individual accounts receivable.
(c): Payments of claims and related costs.
(d): Expenditures for site investigation and remediation.
(e): Result of New England Holdings asset acquisition in November 2002.

270

The individual financial statements and schedules of Exelon's and ComEd's unconsolidated wholly-owned subsidiaries have been omitted from their respective Annual Reports on Form 10-K because the investments are not material in relation to their respective financial positions or results of operations. As of December 31, 2001, the assets of the unconsolidated subsidiaries, in the aggregate, were less than 1% of Exelon's and ComEd's consolidated assets. The 2001 revenues of the unconsolidated subsidiaries, in the aggregate, were less than 1% of Exelon's and ComEd's consolidated annual revenues.

(b): Reports on Form 8-K

Exelon, ComEd, PECO and/or Generation filed Current Reports on Form 8-K during the fourth quarter of 2002 regarding the following items:

Date of Earliest Event Reported		Description of Item Reported
October 2, 2002		"ITEM 5. OTHER EVENTS" filed by Exelon, ComEd and Generation, regarding Generation's exercise of certain options under its purchased power agreement with Midwest Generation, LLC.
October 10, 2002		"ITEM 5. OTHER EVENTS" filed by Exelon and ComEd, regarding the results of the audit by Liberty Consulting Group related to the pending Delivery Services Rate Case.
October 14, 2002		"ITEM 5. OTHER EVENTS" filed by Exelon, announcing that Robert S. Shapard accepted the position of Executive Vice President and Chief Financial Officer.
October 18, 2002		"ITEM 5. OTHER EVENTS" filed by Exelon, ComEd, PECO and Generation, announcing Exelon's expected third quarter 2002 earnings and its plans to restate other comprehensive income.
October 21, 2002		"ITEM 5. OTHER EVENTS" filed by Exelon, ComEd, PECO and Generation, regarding Exelon's presentation at the Edison Electric Institute Financial Conference.
October 30, 2002		"ITEM 5. OTHER EVENTS" filed by Exelon, ComEd, PECO and Generation regarding the announcement of Exelon's third quarter earnings and the closing of Generation's acquisition of Sithe New England Holdings, LLC and "ITEM 9. REGULATION FD DISCLOSURE" filed by Exelon, ComEd, PECO and Generation regarding comments made during the third quarter earnings conference call and the financial impact of the Sithe New England Holdings Acquisition.
November 4, 2002		"ITEM 5. OTHER EVENTS" filed by Exelon, ComEd, PECO and Generation announcing that effective November 4, 2002, Robert S. Shapard assumed the role of Chief Financial Officer and Exelon renewed its $1.5 billion credit facility, in which ComEd, PECO and Generation participate.
December 19, 2002		"ITEM 9. REGULATION FD DISCLOSURE" filed by Exelon and Generation regarding the note to Exelon's financial community related to an update on its Sithe investment.

271

(c): Exhibits

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

Exhibit No.		Description
2-1		Amended and Restated Agreement and Plan of Merger dated as of October 20, 2000, among PECO Energy Company, Exelon Corporation and Unicom Corporation (File No. 1-01401, PECO Energy Company Form 10-Q for the quarter ended September 30, 2000, Exhibit 2-1).
3-1		Articles of Incorporation of Exelon Corporation (Registration Statement No. 333-37082, Form S-4, Exhibit 3-1).
3-2		Bylaws of Exelon Corporation (Registration Statement No. 333-37082, Form S-4, Exhibit 3-2).
3-3		Amended and Restated Articles of Incorporation of PECO Energy Company (File No. 1-01401, 2000 Form 10-K, Exhibit 3-3).
3-4		Bylaws of PECO Energy Company, adopted February 26, 1990 and amended January 26, 1998 (File No. 1-01401, 1997 Form 10-K, Exhibit 3-2).
3-5		Restated Articles of Incorporation of Commonwealth Edison Company effective February 20, 1985, including Statements of Resolution Establishing Series, relating to the establishment of three new series of Commonwealth Edison Company preference stock known as the "$9.00 Cumulative Preference Stock," the "$6.875 Cumulative Preference Stock" and the "$2.425 Cumulative Preference Stock" (File No. 1-1839, 1994 Form 10-K, Exhibit 3-2).
3-6		Bylaws of Commonwealth Edison Company, effective September 2, 1998, as amended through October 20, 2000 (File No. 1-1839, 2000 Form 10-K, Exhibit 3-6).
3-7		Certificate of Formation of Exelon Generation Company, LLC (Registration Statement No. 333-85496, Form S-4, Exhibit 3-1).
3-8		Exelon Generation Company, LLC Operating Agreement (Registration Statement No. 333-85496, Form S-4, Exhibit 3-2).
4-1		$1,500,000,000 Credit Agreement dated as of November 22, 2002 among Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC as Borrowers, various financial institutions named therein as Lenders, Bank One, NA, as Administrative Agent, ABN AMRO Bank, N.V. and Dresden Bank AG, New York and Grand Cayman Branches, as Co-Documentation Agents and Citibank, N.A. and Wachovia Bank, National Association, as Co-Syndication Agents, and Banc One Capital Markets, Inc., as Lead Arranger and Sole Book Runner.
4-2		First and Refunding Mortgage dated May 1, 1923 between The Counties Gas and Electric Company (predecessor to PECO Energy Company) and Fidelity Trust Company, Trustee (First Union National Bank, successor), (Registration No. 2-2281, Exhibit B-1).

272

4-2-1	Supplemental Indentures to PECO Energy Company's First and Refunding Mortgage:
	Dated as of	File Reference	Exhibit No.
	May 1, 1927	2-2881	B-1(c)
	March 1, 1937	2-2881	B-1(g)
	December 1, 1941	2-4863	B-1(h)
	November 1, 1944	2-5472	B-1(i)
	December 1, 1946	2-6821	7-1(j)
	September 1, 1957	2-13562	2(b)-17
	May 1, 1958	2-14020	2(b)-18
	March 1, 1968	2-34051	2(b)-24
	March 1, 1981	2-72802	4-46
	March 1, 1981	2-72802	4-47
	December 1, 1984	1-01401, 1984 Form 10-K	4-2(b)
	April 1, 1991	1-01401, 1991 Form 10-K	4(e)-76
	December 1, 1991	1-01401, 1991 Form 10-K	4(e)-77
	June 1, 1992	1-01401, June 30, 1992 Form 10-Q	4(e)-81
	March 1, 1993	1-01401, 1992 Form 10-K	4(e)-86
	May 1, 1993	1-01401, March 31, 1993 Form 10-Q	4(e)-88
	May 1, 1993	1-01401, March 31, 1993 Form 10-Q	4(e)-89
	August 15, 1993	1-01401, Form 8-A dated August 19, 1993	4(e)-92
	May 1, 1995	1-01401, Form 8-K dated May 24, 1995	4(e)-96
	September 15, 2002	1-01401, September 30, 2002 Form 10-Q	4-1
	October 1, 2002	1-01401, September 30, 2002 Form 10-Q	4-2
4-3	Exelon Corporation Dividend Reinvestment and Stock Purchase Plan (Registration Statement No. 333-84446, Form S-3, Prospectus).
4-4	Mortgage of Commonwealth Edison Company to Illinois Merchants Trust Company, Trustee (BNY Midwest Trust Company, as current successor Trustee), dated July 1, 1923, as supplemented and amended by Supplemental Indenture thereto dated August 1, 1944. (File No. 2-60201, Form S-7, Exhibit 2-1).

273

4-4-1	Supplemental Indentures to aforementioned Commonwealth Edison Mortgage.
	Dated as of	File Reference	Exhibit No.
	August 1, 1946	2-60201, Form S-7	2-1
	April 1, 1953	2-60201, Form S-7	2-1
	March 31, 1967	2-60201, Form S-7	2-1
	April 1,1967	2-60201, Form S-7	2-1
	February 28, 1969	2-60201, Form S-7	2-1
	May 29, 1970	2-60201, Form S-7	2-1
	June 1, 1971	2-60201, Form S-7	2-1
	April 1, 1972	2-60201, Form S-7	2-1
	May 31, 1972	2-60201, Form S-7	2-1
	June 15, 1973	2-60201, Form S-7	2-1
	May 31, 1974	2-60201, Form S-7	2-1
	June 13, 1975	2-60201, Form S-7	2-1
	May 28, 1976	2-60201, Form S-7	2-1
	June 3, 1977	2-60201, Form S-7	2-1
	May 17, 1978	2-99665, Form S-3	4-3
	August 31, 1978	2-99665, Form S-3	4-3
	June 18, 1979	2-99665, Form S-3	4-3
	June 20, 1980	2-99665, Form S-3	4-3
	April 16, 1981	2-99665, Form S-3	4-3
	April 30, 1982	2-99665, Form S-3	4-3
	April 15, 1983	2-99665, Form S-3	4-3
	April 13, 1984	2-99665, Form S-3	4-3
	April 15, 1985	2-99665, Form S-3	4-3
	April 15, 1986	33-6879, Form S-3	4-9
	June 15, 1990	33-38232, Form S-3	4-12
	October 1, 1991	33-40018, Form S-3	4-13
	October 15, 1991	33-40018, Form S-3	4-14
	May 15, 1992	33-48542, Form S-3	4-14
	September 15, 1992	33-53766, Form S-3	4-14
	February 1, 1993	1-1839, 1992 Form 10-K	4-14
	April 1, 1993	33-64028, Form S-3	4-12
	April 15, 1993	33-64028, Form S-3	4-13
	June 15, 1993	1-1839, Form 8-K dated May 21, 1993	4-1
	July 15, 1993	1-1839, Form 10-Q for quarter ended June 30, 1993.	4-1
	January 15, 1994	1-1839, 1993 Form 10-K	4-15
	December 1, 1994	1-1839, 1994 Form 10-K	4-16
	June 1, 1996	1-1839, 1996 Form 10-K	4-16
	March 1, 2002	1-1839, 2001 Form 10-K	4-4-1
	May 20, 2002
	June 1, 2002
	October 7, 2002
	January 13, 2003	1-1839, Form 8-K	4-4
4-4-2	Instrument of Resignation, Appointment and Acceptance dated as of February 20, 2002, under the provisions of the Mortgage dated July 1, 1923, and Indentures Supplemental thereto, regarding corporate trustee (File No. 1-1839, 2001 Form 10-K, Exhibit 4-4-2).
4-4-3	Instrument dated as of January 31, 1996, under the provisions of the Mortgage dated July 1, 1923 and Indentures Supplemental thereto, regarding individual trustee (File No. 1-1839, 1995 Form 10-K, Exhibit 4-29).

274

4-5	Indenture dated as of September 1, 1987 between Commonwealth Edison Company and Citibank, N.A., Trustee relating to Notes (File No. 1-1839, Form S-3, Exhibit 4-13).
4-6-1	Supplemental Indentures to aforementioned Indenture.
	Dated as of	File Reference	Exhibit No.
	September 1, 1987	33-32929, Form S-3	4-16
	January 1, 1997	1-1839, 1999 Form 10-K	4-21
	September 1, 2000	1-1839, 2000 Form 10-K	4-7-3
4-7	Indenture dated June 1, 2001 between Generation and First Union National Bank (now Wachovia Bank, National Association) (Registration Statement No. 333-85496, Form S-4, Exhibit 4.1).
10-1	Stock Purchase Agreement among Exelon (Fossil) Holdings, Inc., as Buyer and The Stockholders of Sithe Energies, Inc., as Sellers, and Sithe Energies, Inc. (File No. 0-16844, PECO Energy Company Form 10-Q for the quarter ended September 30, 2000, Exhibit 10-1).
10-2	$1,250,000,000 Credit and Reimbursement Agreement dated as of January 31, 2001 by and among Exelon Boston Generating, LLC (successor to Sithe Boston Generating, LLC), as Borrower, the Lenders named therein, Bayerische Landesbank Girozentrale, as DSR LC Issuer, BNP Paribas, as Administrative Agent.
10-3	Power Purchase Agreement among Generation and PECO (Registration Statement No. 333-85496, Form S-4, Exhibit 10.1).
10-4	Power Purchase Agreement among Generation and ComEd (Registration Statement No. 333-85496, Form S-4, Exhibit 10.2).
10-5	Amended and restated employment agreement between Exelon Corporation and John W. Rowe dated as of November 26, 2001* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-2).
10-6	Separation Agreement between Exelon and Corbin A. McNeill, Jr., dated as of April 23, 2002* (File No. 1-16169, March 31, 2002 Form 10-Q, Exhibit 10-1).
10-7	Employment Agreement by and among Exelon Corporation, Exelon Generation Company, LLC and Oliver D. Kingsley, Jr. dated as of September 5, 2002* (File Nos. 1-16169 and 333-85496, September 30, 2002 Form 10-Q, Exhibit 10-1).
10-8	Exelon Corporation Deferred Compensation Plan (File No. 1-16169, 2001 Form 10-K, Exhibit 10-3).
10-9	Exelon Corporation Retirement Program (File No. 1-16169, 2001 Form 10-K, Exhibit 10-4).
10-10	PECO Energy Company Unfunded Deferred Compensation Plan for Directors* (Registration Statement No. 333-49780, Form S-8, Exhibit 4-4).
10-11	Exelon Corporation Long-Term Incentive Plan As Amended and Restated effective January 28, 2002 * (File No. 1-16169, Exelon Proxy Statement dated March 13, 2002, Appendix B).
10-11-1	Form of Restricted Stock Award Agreement under the Exelon Corporation Long-Term Incentive Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-6-1).
10-11-2	Forms of Transferable Stock Option Award Agreement under the Exelon Corporation Long-Term Incentive Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-6-2).
10-11-3	Forms of Stock Option Award Agreement under the Exelon Corporation Long-Term Incentive Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-6-3).

275

10-12		PECO Energy Company Management Incentive Compensation Plan *(File No. 1-01401, 1997 Proxy Statement, Appendix A).
10-13		PECO Energy Company 1998 Stock Option Plan *(Registration Statement No. 333-37082, Post-Effective Amendment No. 1 to Form S-4, Exhibit 4-3).
10-14		Exelon Corporation Employee Savings Plan (File No. 1-16169, 2001 Form 10-K, Exhibit 10-9).
10-15		Second Amended and Restated Trust Agreement for PECO Energy Transition Trust (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated May 2, 2000, Exhibit 4.1).
10-16		Indenture dated as of March 1, 1999 between PECO Energy Transition Trust and The Bank of New York. (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated March 25, 1999, Exhibit 4.3.1).
10-16-1		Series Supplement dated as of March 25, 1999 between PECO Energy Transition Trust and The Bank of New York. (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated March 25, 1999, Exhibit 4.3.2).
10-16-2		Series Supplement dated as of March 1, 2001 between PECO Energy Transition Trust and The Bank of New York. (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated March 1, 2001, Exhibit 4.3.2).
10-16-3		Series Supplement dated as of May 2, 2000 between PECO Energy Transition Trust and The Bank of New York (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated May 2, 2000, Exhibit 4.3.2).
10-17		Intangible Transition Property Sale Agreement dated as of March 25,1999, as amended and restated as of May 2, 2000, between PECO Energy Transition Trust and PECO Energy Company. (File No. 333-58055, PECO Energy Transition Trust Report on Form 8-K dated May 2, 2000, Exhibit 10.1).
10-17-1		Amendment No. 1 to Intangible Transition Property Sale Agreement dated as of March 25, 1999, as amended and restated as of May 2, 2000 (File No. 1-01401, PECO Energy Company and PECO Energy Transition Trust Report on Form 8-K dated March 1, 2001).
10-18		Master Servicing Agreement dated as of March 25, 1999, as amended and restated as of May 2, 2000, between PECO Energy Transition Trust and PECO Energy Company. (File No. 333-58055, PECO Energy Transition Trust Current Report on Form 8-K dated May 2, 2000, Exhibit 10.2).
10-18-1		Amendment No. 1 to Master Servicing Agreement dated as of March 25, 1999, as amended and restated as of May 2, 2000 (File No. 1-01401, PECO Energy Company and PECO Energy Transition Trust Report on Form 8-K dated March 1, 2001).
10-19		Exelon Corporation Cash Balance Pension Plan (File No. 1-16169, 2001 Form 10-K, Exhibit 10-14).
10-20		Joint Petition for Full Settlement of PECO Energy Company's Restructuring Plan and Related Appeals and Application for a Qualified Rate Order and Application for Transfer of Generation Assets dated April 29, 1998. (Registration Statement No. 333-58055, Exhibit 10.3).
10-21		Joint Petition for Full Settlement of PECO Energy Company's Application for Issuance of Qualified Rate Order Under Section 2812 of the Public Utility Code dated March 8, 2000 (Amendment No. 1 to Registration Statement No. 333-31646, Exhibit 10.4).

276

10-22		Unicom Corporation Amended and Restated Long-Term Incentive Plan *(File No. 1-11375, Unicom Proxy Statement dated April 7, 1999, Exhibit A).
10-22-1		First Amendment to Unicom Corporation Amended and Restated Long Term Incentive Plan *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-8).
10-22-2		Second Amendment to Unicom Corporation Amended and Restated Long Term Incentive Plan *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-9).
10-23		Unicom Corporation General Provisions Regarding 1996 Stock Option Awards Granted under the Unicom Corporation and Long-Term Incentive Plan. *(File Nos. 1-11375 and 1-1839, 1996 Form 10-K, Exhibit 10-9).
10-24		Unicom Corporation General Provisions Regarding 1996B Stock Option Awards Granted under the Unicom Corporation Long-Term Incentive Plan. *(File Nos. 1-11375 and 1-1839, 1996 Form 10-K, Exhibit 10-8).
10-25		Unicom Corporation General Provisions Regarding Stock Option Awards Granted under the Unicom Corporation Long-Term Incentive Plan (Effective July 10, 1997) (File Nos. 1-11375 and 1-1839, 1999 Form 10-K, Exhibit 10-8).
10-26		Unicom Corporation Deferred Compensation Unit Plan, as amended *(File Nos. 1-11375 and 1-1839, 1995 Form 10-K, Exhibit 10-12).
10-27		Exelon Corporation Corporate Stock Deferral Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-22).
10-28		Unicom Corporation Retirement Plan for Directors, as amended *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-12).
10-29		Commonwealth Edison Company Retirement Plan for Directors, as amended *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-13).
10-30		Unicom Corporation 1996 Directors' Fee Plan *(File No. 1-11375, Unicom Proxy Statement dated April 8, 1996, Appendix A).
10-30-1		Second Amendment to Unicom Corporation 1996 Directors Fee Plan *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-11).
10-31		Change in Control Agreement between Unicom Corporation, Commonwealth Edison Company and certain senior executives * (File Nos. 1-11375 and 1-1839, 1998 Form 10-K, Exhibit 10-24).
10-31-1		Forms of Change in Control Agreement Between PECO Energy Company and Certain Employees * (File No. 1-1401, 2000 Form 10-K, Exhibit 10-25-1).
10-32		Commonwealth Edison Company Executive Group Life Insurance Plan *(File No. 1-1839, 1980 Form 10-K, Exhibit 10-3).
10-32-1		Amendment to the Commonwealth Edison Company Executive Group Life Insurance Plan *(File No. 1-1839, 1981 Form 10-K, Exhibit 10-4).
10-32-2		Amendment to the Commonwealth Edison Company Executive Group Life Insurance Plan dated December 12, 1986 *(File No. 1-1839, 1986 Form 10-K, Exhibit 10-6).
10-32-3		Amendment to the Commonwealth Edison Company Executive Group Life Insurance Plan to implement program of "split dollar life insurance" dated December 13, 1990 *(File No. 1-1839, 1990 Form 10-K, Exhibit 10-10).
10-32-4		Amendment to Commonwealth Edison Company Executive Group Life Insurance Plan to stabilize the death benefit applicable to participants dated July 22, 1992 *(File No. 1-1839, 1992 Form 10-K, Exhibit 10-13).

277

10-33		First Amendment to Exelon Corporation Employee Savings Plan (File No. 1-16169, 2001 Form 10-K, Exhibit 10-29).
10-33-1		First Amendment to the Commonwealth Edison Company Supplemental Management Retirement Plan. * (File No. 1-1839, 2000 Form 10-K, Exhibit 10-27-1)
10-34		Second Amendment and Restated Exelon Corporation Key Management Severance Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-30).
10-35		Forms of Change in Control Agreement between Exelon Corporation and certain senior executives (File No. 1-16169, 2001 Form 10-K, Exhibit 10-31).
10-36		Amendment No. 1 to Exelon Corporation Supplemental Management Retirement Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-32).
10-37		Form of Stock Award Agreement under the Unicom Corporation Long-Term Incentive Plan *(File Nos. 1-11375 and 1-1839, 1997 Form 10-K, Exhibit 10-37).
10-38		Amended and Restated Key Management Severance Plan for Unicom Corporation and Commonwealth Edison Company dated March 8, 1999 * (File No. 1-1839, 1999 Form 10-K, Exhibit 10-38).
10-38-1		Exelon Corporation Employee Stock Purchase Plan (Registration Statement No. 333-61390, Form S-8, Exhibit 4.2).
10-38-2		First Amendment to the Exelon Corporation Employee Stock Purchase Plan (File No. 1-16169, 2001 Form 10-K, Exhibit 10-34-2).
10-39		PECO Energy Company Supplemental Pension Benefit Plan (As Amended and Restated January 1, 2001)* (File No. 1-1401, 2001 Form 10-K, Exhibit 10-35).
10-40		Exelon Corporation 2001 Performance Share Awards for Power Team Employees under the Exelon Corporation Long Term Incentive Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-36).
10-41		Agreement Regarding Various Matters Involving or Affecting Rates for Electric Service Offered by Commonwealth Edison Company dated as of March 3, 2003 among Commonwealth Edison Company and the other parties named therein.
10-41-1		Amendment dated as of March 10, 2003 to the Agreement Regarding Various Matters Involving or Affecting Rates for Electric Service Offered by Commonwealth Edison Company.
16		Arthur Andersen Letter to Securities and Exchange Commission regarding the change in certifying accountant (File No. 1-01839, Exelon Corporation Report on Form 8-K dated November 28, 2000, Exhibit 16).
18-1		Letter from PricewaterhouseCoopers LLP addressed to Exelon Corporation concerning a change in accounting principles (File No. 1-16169, 2000 Form 10-K from PricewaterhouseCoopers LLP addressed to Exelon Corporation concerning a change in accounting principles (File No. 1-16169, 2000 Form 10-K, Exhibit 18-1).
18-2		Letter from PricewaterhouseCoopers LLP addressed to PECO Energy Company concerning a change in accounting principles (File No. 1-1401, 2000 Form 10-K, Exhibit 18-2).
21		Subsidiaries
21-1		Exelon Corporation
21-2		Commonwealth Edison Company (File No. 1-1839, 2000 Form 10-K, Exhibit 21-3).
21-3		PECO Energy Company (File No. 1-1401, 2000 Form 10-K, Exhibit 21-2).

278

23		Consent of Independent Accountants
23-1		Exelon Corporation
23-2		Commonwealth Edison Company
23-3		PECO Energy Company
24		Power of Attorney
24-1		Edward A. Brennan
24-2		Carlos H. Cantu
24-3		M. Walter D'Alessio
24-4		Nicholas DeBenedictis
24-5		Bruce DeMars
24-6		G. Fred DiBona, Jr.
24-7		Reserved
24-8		Richard H. Glanton
24-9		Reserved
24-10		Edgar D. Jannotta
24-11		John M. Palms, Ph.D.
24-12		John W. Rogers, Jr.
24-13		Ronald Rubin
24-14		Richard L. Thomas
99-1		Exelon Corporation's Current Report on Form 8-K dated February 21, 2003, (File No. 1-16169).
		Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes—Oxley Act of 2002) as to the Annual Report on Form 10-K for the year ended December 31, 2002 filed by the following officers for the following registrants:
99-2		Filed by John W. Rowe for Exelon Corporation
99-3		Filed by Robert S. Shapard for Exelon Corporation
99-4		Filed by Pamela B. Strobel for Commonwealth Edison Company
99-5		Filed by Robert S. Shapard for Commonwealth Edison Company
99-6		Filed by Pamela B. Strobel for PECO Energy Company
99-7		Filed by Robert S. Shapard for PECO Energy Company
99-8		Filed by Oliver D. Kingsley for Exelon Generation Company, LLC
99-9		Filed by Robert S. Shapard for Exelon Generation Company, LLC

*: Compensatory plan or arrangements in which directors or officers of the applicable registrant participate and which are not available to all employees.

279

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 21st day of March, 2003.

EXELON CORPORATION

By:	/s/ JOHN W. ROWE
	Name:	John W. Rowe
	Title:	Chairman, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on the 21st day of March, 2003.

Signature		Title

/s/ JOHN W. ROWE John W. Rowe		Chairman, President and Chief Executive Officer (Principal Executive Officer)
/s/ ROBERT S. SHAPARD Robert S. Shapard		Executive Vice President and Chief Financial Officer (Principal Financial Officer)
/s/ MATTHEW F. HILZINGER Matthew F. Hilzinger		Vice President and Corporate Controller (Principal Accounting Officer)

This annual report has also been signed below by John W. Rowe, Attorney-in-Fact, on behalf of the following Directors on the date indicated:

EDWARD A. BRENNAN
CARLOS H. CANTU
M. WALTER D'ALESSIO
NICHOLAS DEBENEDICTIS
BRUCE DEMARS
G. FRED DIBONA, JR.

RICHARD H. GLANTON
EDGAR D. JANNOTTA
JOHN M. PALMS, PH.D.
JOHN W. ROGERS, JR.
RONALD RUBIN
RICHARD L. THOMAS


By:	/s/ JOHN W. ROWE Name: John W. Rowe Title: Chairman, President and Chief Executive Officer		March 21, 2003

280

SIGNATURES

COMMONWEALTH EDISON COMPANY

By:	/s/ JOHN W. ROWE
	Name:	John W. Rowe
	Title:	Chairman, President and Chief Executive Officer, Exelon and Director

Signature		Title

/s/ JOHN W. ROWE John W. Rowe		Chairman, President and Chief Executive Officer, Exelon and Director
/s/ PAMELA B. STROBEL Pamela B. Strobel		Chair (Principal Executive Officer)
/s/ ROBERT S. SHAPARD Robert S. Shapard		Executive Vice President and Chief Financial Officer, Exelon (Principal Financial Officer)
/s/ FRANK M. CLARK Frank M. Clark		President and Director
/s/ KATHRYN M. HOUTSMA Kathryn M. Houtsma		Vice President, Finance (Principal Accounting Officer)
/s/ RUTH ANN M. GILLIS Ruth Ann M. Gillis		Director
/s/ KENNETH G. LAWRENCE Kenneth G. Lawrence		Director

281

SIGNATURES

PECO ENERGY COMPANY

By:	/s/ JOHN W. ROWE
	Name:	John W. Rowe
	Title:	Chairman, President and Chief Executive Officer, Exelon and Director

Signature		Title

/s/ JOHN W. ROWE John W. Rowe		Chairman, President and Chief Executive Officer, Exelon and Director
/s/ PAMELA B. STROBEL Pamela B. Strobel		Chair (Principal Executive Officer)
/s/ ROBERT S. SHAPARD Robert S. Shapard		Executive Vice President and Chief Financial Officer, Exelon (Principal Financial Officer)
/s/ KENNETH G. LAWRENCE Kenneth G. Lawrence		President and Director
/s/ FRANK F. FRANKOWSKI Frank F. Frankowski		Vice President, Finance (Principal Accounting Officer)
/s/ RUTH ANN M. GILLIS Ruth Ann M. Gillis		Director

282

SIGNATURES

EXELON GENERATION COMPANY, LLC

By:	/s/ JOHN W. ROWE
	Name:	John W. Rowe
	Title:	Chairman, President and Chief Executive Officer, Exelon

Signature		Title

/s/ JOHN W. ROWE John W. Rowe		Chairman, President and Chief Executive Officer, Exelon
/s/ OLIVER D. KINGSLEY JR. Oliver D. Kingsley Jr.		Chief Executive Officer and President (Principal Executive Officer)
/s/ ROBERT S. SHAPARD Robert S. Shapard		Executive Vice President and Chief Financial Officer, Exelon (Principal Financial and Accounting Officer)
/s/ THOMAS H. WEIR Thomas H. Weir		Controller

283

CERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14
OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, John W. Rowe, certify that:

1.

I have reviewed this annual report on Form 10-K of Exelon Corporation;

2.

Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.

Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.

The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a): designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b): evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c): presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a): all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b): any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.: The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 21, 2003

/s/ JOHN W. ROWE

Chairman, President and Chief Executive Officer
(Principal Executive Officer)

284

CERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14
OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Robert S. Shapard, certify that:

1.

I have reviewed this annual report on Form 10-K of Exelon Corporation;

2.

3.

4.

a): designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b): evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c): presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

a): all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b): any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.: The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 21, 2003

/s/ ROBERT S. SHAPARD

Executive Vice President and Chief Financial Officer
(Principal Financial Officer)

285

CERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14
OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Pamela B. Strobel, certify that:

1.

I have reviewed this annual report on Form 10-K of Commonwealth Edison Company;

2.

3.

4.

a): designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b): evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c): presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

a): all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b): any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.: The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 21, 2003

/s/ PAMELA B. STROBEL

Chair
(Principal Executive Officer)

286

CERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14
OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Robert S. Shapard, certify that:

1.

I have reviewed this annual report on Form 10-K of Commonwealth Edison Company;

2.

3.

4.

a): designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b): evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c): presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

a): all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b): any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.: The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 21, 2003

/s/ ROBERT S. SHAPARD

Executive Vice President and Chief Financial Officer, Exelon
(Principal Financial Officer)

287

CERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14
OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Pamela B. Strobel, certify that:

1.

I have reviewed this annual report on Form 10-K of PECO Energy Company;

2.

3.

4.

a): designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b): evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c): presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

a): all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b): any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.: The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 21, 2003

/s/ PAMELA B. STROBEL

Chair
(Principal Executive Officer)

288

CERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14
OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Robert S. Shapard, certify that:

1.

I have reviewed this annual report on Form 10-K of PECO Energy Company;

2.

3.

4.

a): designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b): evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c): presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

a): all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b): any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.: The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 21, 2003

/s/ ROBERT S. SHAPARD

Executive Vice President and Chief Financial Officer, Exelon
(Principal Financial Officer)

289

CERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14
OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Oliver D. Kingsley Jr., certify that:

1.

I have reviewed this annual report on Form 10-K of Exelon Generation Company, LLC;

2.

3.

4.

a): designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b): evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c): presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

a): all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b): any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.: The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 21, 2003

/s/ OLIVER D. KINGSLEY JR.

Chief Executive Officer and President
(Principal Executive Officer)

290

CERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14
OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Robert S. Shapard, certify that:

1.

I have reviewed this annual report on Form 10-K of Exelon Generation Company, LLC;

2.

3.

4.

a): designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b): evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c): presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

a): all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b): any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.: The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 21, 2003

/s/ ROBERT S. SHAPARD

Executive Vice President and Chief Financial Officer, Exelon
(Principal Financial Officer)

291

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TABLE OF CONTENTS
FORWARD-LOOKING STATEMENTS
WHERE TO FIND MORE INFORMATION
PART I

ITEM 1. BUSINESS

ITEM 2. PROPERTIES

ITEM 3. LEGAL PROCEEDINGS

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

PART II

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