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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWASHINGTON, D.C. 20549

FORM 10-K

|ý                                           |  | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934    
|------------------------------------------- |  | ----------------------------------------------------------------------------------------
|For the Fiscal Year Ended December 31, 2002
|OR                                         
|o                                           |  | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

|Commission File
Number |  | Name of Registrant; State of Incorporation; Address of
Principal Executive Offices; and Telephone Number                                                |  | IRS Employer
Identification Number
|---------------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------------------------------
|1-16169                |  | EXELON CORPORATION
(a Pennsylvania corporation)
10 South Dearborn Street  37th Floor
P.O. Box 805379
Chicago, Illinois 60680-5379
(312) 394-7398       |  | 23-2990190                        
|1-1839                 |  | COMMONWEALTH EDISON COMPANY
(an Illinois corporation)
10 South Dearborn Street  37th Floor
P.O. Box 805379
Chicago, Illinois 60680-5379
(312) 394-4321 |  | 36-0938600                        
|1-1401                 |  | PECO ENERGY COMPANY
(a Pennsylvania corporation)
P.O. Box 8699
2301 Market Street
Philadelphia, Pennsylvania 19101-8699
(215) 841-4000                  |  | 23-0970240                        
|333-85496              |  | EXELON GENERATION COMPANY, LLC
(a Pennsylvania limited liability company)
300 Exelon Way
Kennett Square, Pennsylvania 19348
(610) 765-6900              |  | 23-3064219                        

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

|Title of Each Class                                                                                                                                                                                                                            |  | Name of Each
Exchange on Which Registered
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | -----------------------------------------
|EXELON CORPORATION:                                                                                                                                                                                                                            |  |                                          
|Common Stock, without par value                                                                                                                                                                                                                |  | New York, Chicago and Philadelphia       
|COMMONWEALTH EDISON COMPANY:                                                                                                                                                                                                                   |  |                                          
|Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Commonwealth Edison Company's 8.48% Subordinated Debt Securities and unconditionally guaranteed by Commonwealth
Edison Company                |  | New York                                 
|PECO ENERGY COMPANY:                                                                                                                                                                                                                           |  |                                          
|First and Refunding Mortgage Bonds: 63/8% Series due 2005, and 61/2% Series due 2003                                                                                                                                                           |  | New York                                 
|Cumulative Preferred Stock, without par value: $4.68 Series, $4.40 Series, $4.30 Series and $3.80 Series                                                                                                                                       |  | New York                                 
|Trust Receipts of PECO Energy Capital Trust II, each representing an 8.00% Cumulative Monthly Income Preferred Security, Series C, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy
Company |  | New York                                 
|Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by
PECO Energy Company                |  | New York                                 

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

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

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

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

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

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

Exelon Corporation

Yes ý

No oCommonwealth Edison Company

Yes o

No ýPECO Energy Company

Yes o

No ýExelon Generation Company, LLC

Yes o

No ý


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

Exelon Corporation Common Stock, without par value

$16,886,511,503Commonwealth Edison Company Common Stock, $12.50 par value

No established marketPECO Energy Company Common Stock, without par value

NoneExelon 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

324,068,637Commonwealth Edison Company Common Stock, $12.50 par value

127,016,425PECO Energy Company Common Stock, without par value

170,478,507Exelon 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.

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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                                                                                           

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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.govand Exelon Corporation's website at www.exeloncorp.com.

1

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PART I

ITEM 1. BUSINESS

General

Exelon Corporation (Exelon) was incorporated in Pennsylvania in February 1999. On October 20, 2000, Exelon became the parent corporation for PECO
Energy Company (PECO) and Commonwealth Edison Company (ComEd) as a result of a merger among PECO, Unicom Corporation (Unicom), the former parent company of ComEd, and Exelon (Merger). The Merger was
accounted for using the purchase method of accounting with PECO as the acquiring company. Accordingly, Exelon's results of operations for 2000 consist of PECO's results of operations for 2000 and
Unicom's results of operations after October 20, 2000.

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

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



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

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

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

Energy Delivery

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

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

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

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

3

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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).

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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.

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

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

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

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

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

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

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

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

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

7

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

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

The
Agreement addresses, among other things:









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

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

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

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

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

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

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

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

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

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

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

|     |  | Allowed Recovery,
Excluding Gross
Receipts Tax
|---- |  | ----------------------------------------------
|
|
|
|2003 |  | 818,352                                       
|2004 |  | 811,540                                       
|2005 |  | 807,933                                       
|2006 |  | 902,623                                       
|2007 |  | 909,844                                       
|2008 |  | 917,123                                       
|2009 |  | 924,459                                       
|2010 |  | 931,855                                       

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

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

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

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

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

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

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

Transmission Services

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

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

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

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

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

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

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

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

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

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

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Gas

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

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

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

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

Construction Budget

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

|                              |  | ComEd |     | PECO
|----------------------------- |  | ----- | --- | ----
|
|Transmission and Distribution |  | $     | 634 |     
|Gas                           |  |       |    |     
|Other                         |  |       | 86  |     
|                              |  |       |     |     
|Total                         |  | $     | 720 |     
|                              |  |       |     |     

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

Generation

General

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

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

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

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

Generating Resources

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

|Type of Capacity             |         | MW                        
|---------------------------- | ------- | --------------------------
|Owned Generation Assets(1,2) |         |                           
|                             | Nuclear |                           
|                             | Fossil  |                           
|                             | Hydro   |                           
|                             |         |                           
|                             |         | 24,341                    
|Long-term Contracts(3)       |         | 13,900                    
|AmerGen and Sithe(2)         |         | 1,900                     
|                             |         |                           
|                             |         | Available Resources       
|Under Construction(2)        |         | 2,536                     
|                             |         |                           
|                             |         | Total Generating Resources
|                             |         |                           

---

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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



Fossil units include:



Hydroelectric
facilities include:



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

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



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

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

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

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

Long-Term Contracts

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

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

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

Federal Power Act

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

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

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

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

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

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

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

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

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

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

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

Fuel

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

|                                   |  | Source of Electric Supply
|---------------------------------- |  | -------------------------
|
|Nuclear units(1)                   |  | 115,854                  
|Purchasesnon-trading portfolio(2) |  | 78,710                   
|Fossil and hydro units             |  | 12,976                   
|                                   |  |                          
|Total Supply                       |  | 207,540                  
|                                   |  |                          

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

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

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

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

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

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

Power Team

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

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

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

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

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

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

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

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

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

|           |  |   |       |  |   | Power Only Purchases from |  |  
|---------- |  | - | ----- |  | - | ------------------------- |  | -
|
|2003       |  | $ | 589   |  | $ | 2,442                     |  | $
|2004       |  |   | 639   |  |   | 1,088                     |  |  
|2005       |  |   | 356   |  |   | 272                       |  |  
|2006       |  |   | 328   |  |   | 92                        |  |  
|2007       |  |   | 408   |  |   | 22                        |  |  
|Thereafter |  |   | 3,742 |  |   | 1                         |  |  
|           |  |   |       |  |   |                           |  |  
|Total      |  | $ | 6,062 |  | $ | 3,917                     |  | $
|           |  |   |       |  |   |                           |  |  

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Additionally,
Generation has the following commitments:

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

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

Capital Expenditures

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

|                 |       | (in millions)
|---------------- | ----- | -------------
|Production Plant |       | $            
|Nuclear Fuel     |       |              
|                 |       |              
|                 | Total |              
|                 |       |              

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

Sithe

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

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

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

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

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

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

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

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

AmerGen

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

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

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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                       
|                                            |  |               |  |                      |  |                            |  |                             

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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

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

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

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

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

Employees

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

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

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

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

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

Environmental Regulation

General

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

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

Water

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

Solid and Hazardous Waste

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

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

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

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

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

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

MGP Sites

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

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

Air

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

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

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

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

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

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

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

Costs

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

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

Other Subsidiaries of ComEd and PECO with Publicly Held Securities

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

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

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

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

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

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

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

38

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

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

Executive Officers of the Registrants at December 31, 2002

Exelon

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

ComEd

|Name                 |  | Age |  | Position                                                            
|-------------------- |  | --- |  | --------------------------------------------------------------------
|Rowe, John W.        |  | 57  |  | Chairman, President and Chief Executive Officer, Exelon and Director
|Strobel, Pamela B.   |  | 50  |  | Chair                                                               
|Shapard, Robert S.   |  | 47  |  | Executive Vice President and Chief Financial Officer, Exelon*       
|Clark, Frank M.      |  | 57  |  | President and Director                                              
|Gillis, Ruth Ann M.  |  | 48  |  | Director                                                            
|Lawrence, Kenneth G. |  | 55  |  | Director                                                            
|Dudkin, Gregory N.   |  | 45  |  | Executive Vice President, Operations                                
|Berdelle, Robert E.  |  | 46  |  | Vice President, Finance and Chief Financial Officer*                

---

39

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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                                            

---

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

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

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

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

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

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

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

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

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

40

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

41

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ITEM 2. PROPERTIES

Energy Delivery

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

Transmission and Distribution

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

|      |  | Voltage (Volts)                |  | Circuit Miles  
|----- |  | ------------------------------ |  | ---------------
|ComEd |  | 765,000
345,000
138,000        |  | 90
2,539
2,431 
|PECO  |  | 500,000
220,000
132,000
66,000 |  | 297
496
226
168

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

Gas

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

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

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

Mortgages

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

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

42

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Generation

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

|Station                      |  | Location                  |  | No. of Units |  | Percent Owned(1) |  | Primary Fuel Type |  | Dispatch Type        |  | Net Generation Capacity(MW)(2) |    
|---------------------------- |  | ------------------------- |  | ------------ |  | ---------------- |  | ----------------- |  | -------------------- |  | ------------------------------ | ---
|Nuclear(3)                   |  |                           |  |              |  |                  |  |                   |  |                      |  |                                |    
|Braidwood                    |  | Braidwood, IL             |  | 2            |  |                  |  | Uranium           |  | Base-load            |  | 2,413                          |    
|Byron                        |  | Byron, IL                 |  | 2            |  |                  |  | Uranium           |  | Base-load            |  | 2,393                          |    
|Dresden                      |  | Morris, IL                |  | 2            |  |                  |  | Uranium           |  | Base-load            |  | 1,728                          |    
|LaSalle County               |  | Seneca, IL                |  | 2            |  |                  |  | Uranium           |  | Base-load            |  | 2,325                          |    
|Limerick                     |  | Limerick Twp., PA         |  | 2            |  |                  |  | Uranium           |  | Base-load            |  | 2,316                          |    
|Peach Bottom                 |  | Peach Bottom Twp., PA     |  | 2            |  | 50.00            |  | Uranium           |  | Base-load            |  | 1,130                          | (4)
|Quad Cities                  |  | Cordova, IL               |  | 2            |  | 75.00            |  | Uranium           |  | Base-load            |  | 1,311                          | (4)
|Salem                        |  | Hancock's Bridge, NJ      |  | 2            |  | 42.59            |  | Uranium           |  | Base-load            |  | 931                            | (4)
|                             |  |                           |  |              |  |                  |  |                   |  |                      |  |                                |    
|                             |  |                           |  |              |  |                  |  |                   |  |                      |  | 14,547                         |    
|Fossil (Steam Turbines)      |  |                           |  |              |  |                  |  |                   |  |                      |  |                                |    
|Conemaugh                    |  | New Florence, PA          |  | 2            |  | 20.72            |  | Coal              |  | Base-load            |  | 352                            | (4)
|Cromby 1                     |  | Phoenixville, PA          |  | 1            |  |                  |  | Coal              |  | Base-load            |  | 144                            |    
|Cromby 2                     |  | Phoenixville, PA          |  | 1            |  |                  |  | Oil/Gas           |  | Intermediate         |  | 201                            |    
|Delaware                     |  | Philadelphia, PA          |  | 2            |  |                  |  | Oil               |  | Peaking              |  | 250                            |    
|Eddystone 1, 2               |  | Eddystone, PA             |  | 2            |  |                  |  | Coal              |  | Base-load            |  | 581                            |    
|Eddystone 3, 4               |  | Eddystone, PA             |  | 2            |  |                  |  | Oil/Gas           |  | Intermediate         |  | 760                            |    
|Fairless Hills               |  | Falls Twp., PA            |  | 2            |  |                  |  | Landfill Gas      |  | Peaking              |  | 60                             |    
|Handley                      |  | Fort Worth, TX            |  | 5            |  |                  |  | Gas               |  | Peaking/Intermediate |  | 1,441                          |    
|Keystone                     |  | Shelocta, PA              |  | 2            |  | 20.99            |  | Coal              |  | Base-load            |  | 357                            | (4)
|Mountain Creek               |  | Dallas, TX                |  | 5            |  |                  |  | Gas               |  | Peaking/Intermediate |  | 893                            |    
|Mystic                       |  | Everett, MA               |  | 4            |  |                  |  | Oil/Gas           |  | Intermediate         |  | 995                            |    
|New Boston                   |  | South Boston, MA          |  | 1            |  |                  |  | Gas               |  | Intermediate         |  | 380                            |    
|Schuylkill                   |  | Philadelphia, PA          |  | 1            |  |                  |  | Oil               |  | Peaking              |  | 166                            |    
|Wyman Unit                   |  | Yarmouth, ME              |  | 1            |  | 5.89             |  | Oil               |  | Intermediate         |  | 36                             | (4)
|                             |  |                           |  |              |  |                  |  |                   |  |                      |  |                                |    
|                             |  |                           |  |              |  |                  |  |                   |  |                      |  | 6,616                          |    
|Fossil (Combustion Turbines) |  |                           |  |              |  |                  |  |                   |  |                      |  |                                |    
|Chester                      |  | Chester, PA               |  | 3            |  |                  |  | Oil               |  | Peaking              |  | 39                             |    
|Croydon                      |  | Bristol Twp., PA          |  | 8            |  |                  |  | Oil               |  | Peaking              |  | 380                            |    
|Delaware                     |  | Philadelphia, PA          |  | 4            |  |                  |  | Oil               |  | Peaking              |  | 56                             |    
|Eddystone                    |  | Eddystone, PA             |  | 4            |  |                  |  | Oil               |  | Peaking              |  | 60                             |    
|Falls                        |  | Falls Twp., PA            |  | 3            |  |                  |  | Oil               |  | Peaking              |  | 51                             |    
|Framingham                   |  | Framingham, MA            |  | 3            |  |                  |  | Oil               |  | Peaking              |  | 37                             |    
|LaPorte                      |  | LaPorte, TX               |  | 4            |  |                  |  | Gas               |  | Peaking              |  | 160                            |    
|Moser                        |  | Lower Pottsgrove Twp., PA |  | 3            |  |                  |  | Oil               |  | Peaking              |  | 51                             |    
|Mystic CT                    |  | Everett, MA               |  | 1            |  |                  |  | Oil               |  | Peaking              |  | 12                             |    
|New Boston                   |  | South Boston, MA          |  | 1            |  |                  |  | Gas               |  | Peaking              |  | 20                             |    
|Pennsbury                    |  | Falls Twp., PA            |  | 2            |  |                  |  | Landfill Gas      |  | Peaking              |  | 6                              |    
|Richmond                     |  | Philadelphia, PA          |  | 2            |  |                  |  | Oil               |  | Peaking              |  | 96                             |    
|Salem                        |  | Hancock's Bridge, NJ      |  | 1            |  | 42.59            |  | Oil               |  | Peaking              |  | 16                             | (4)
|Schuylkill                   |  | Philadelphia, PA          |  | 2            |  |                  |  | Oil               |  | Peaking              |  | 30                             |    
|South East Chicago           |  | Chicago, IL               |  | 8            |  |                  |  | Gas               |  | Peaking              |  | 350                            |    
|Southwark                    |  | Philadelphia, PA          |  | 4            |  |                  |  | Oil               |  | Peaking              |  | 52                             |    
|West Medway                  |  | West Medway, MA           |  | 3            |  |                  |  | Oil               |  | Peaking              |  | 165                            |    
|                             |  |                           |  |              |  |                  |  |                   |  |                      |  |                                |    
|                             |  |                           |  |              |  |                  |  |                   |  |                      |  | 1,581                          |    
|(continued on next page)     |  |                           |  |              |  |                  | 

43

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|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 |    
|                                    |  |                   |  |     |  |       |  |         |  |              |  |        |    

---

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

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

ITEM 3. LEGAL PROCEEDINGS

Exelon

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

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

44

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ComEd

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

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

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

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

45

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

PECO

None.

Generation

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

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

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

46

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

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

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

General

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

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

Exelon, ComEd and PECO

None.

47

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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 |  
|------ |  | ---- | ---- | ---- | -
|
|
|Exelon |  | $    | 0.44 |      | $

---

48

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

|      |  | 2002 |     | 2001
|----- |  | ---- | --- | ----
|
|
|ComEd |  | $    | 117 |     
|PECO  |  | $    | 85  |     

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.

49

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ComEd

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

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

|                           |  | For the Years
Ended December 31, |       |  |   |       |  |   |       | For the Years
Ended December 31,
|-------------------------- |  | -------------------------------- | ----- |  | - | ----- |  | - | ----- | --------------------------------
|
|
|
|Statement of Income Data:  |  |                                  |       |  |   |       |  |   |       |                                 
|Operating Revenues         |  | $                                | 6,124 |  | $ | 6,206 |  | $ | 1,310 |                                 
|Operating Income           |  |                                  | 1,766 |  |   | 1,594 |  |   | 338   |                                 
|Net Income                 |  |                                  | 790   |  |   | 607   |  |   | 133   |                                 
|Net Income on Common Stock |  |                                  | 790   |  |   | 607   |  |   | 133   |                                 

|                                                  |  | December 31,
|------------------------------------------------- |  | ------------
|
|
|Balance Sheet Data:                               |  |             
|Current Assets                                    |  | $           
|Property, Plant and Equipment, net                |  |             
|Goodwill, net                                     |  |             
|Other Deferred Debits and Other Assets            |  |             
|                                                  |  |             
|Total Assets                                      |  | $           
|                                                  |  |             
|Current Liabilities                               |  | $           
|Long-Term Debt                                    |  |             
|Deferred Credits and Other Liabilities            |  |             
|Mandatorily Redeemable Preference Stock           |  |             
|Company-Obligated Mandatorily Redeemable          |  |             
|Preferred Securities of Subsidiary Trusts Holding |  |             
|the Company's Subordinated Debt Securities        |  |             
|Shareholders' Equity                              |  |             
|                                                  |  |             
|Total Liabilities and Shareholders' Equity        |  | $           
|                                                  |  |             

50

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PECO

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

|                                                                            |  | For the Years Ended December 31,
|--------------------------------------------------------------------------- |  | --------------------------------
|
|
|Statement of Income Data:                                                   |  |                                 
|Operating Revenues                                                          |  | $                               
|Operating Income                                                            |  |                                 
|Income before Cumulative Effect of a Change in Accounting Principle         |  | $                               
|Cumulative Effect of a Change in Accounting Principle (net of income taxes) |  |                                 
|                                                                            |  |                                 
|Net Income                                                                  |  | $                               
|                                                                            |  |                                 
|Net Income on Common Stock                                                  |  | $                               
|                                                                            |  |                                 

|                                                              |  | December 31,
|------------------------------------------------------------- |  | ------------
|
|
|Balance Sheet Data:                                           |  |             
|Current Assets                                                |  | $           
|Property, Plant and Equipment, net                            |  |             
|Deferred Debits and Other Assets                              |  |             
|                                                              |  |             
|Total Assets                                                  |  | $           
|                                                              |  |             
|Current Liabilities                                           |  | $           
|Long-Term Debt                                                |  |             
|Deferred Credits and Other Liabilities                        |  |             
|Company-Obligated Mandatorily Redeemable Preferred Securities |  |             
|Mandatorily Redeemable Preferred Stock                        |  |             
|Shareholders' Equity                                          |  |             
|                                                              |  |             
|Total Liabilities and Shareholders' Equity                    |  | $           
|                                                              |  |             

51

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Generation

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

|                                                                            |  | For the Years Ended December 31,
|--------------------------------------------------------------------------- |  | --------------------------------
|
|
|Statement of Income Data:                                                   |  |                                 
|Operating Revenues                                                          |  | $                               
|Operating Income                                                            |  |                                 
|Income before Cumulative Effect of Changes in Accounting Principles         |  | $                               
|Cumulative Effect of Changes in Accounting Principles (net of income taxes) |  |                                 
|                                                                            |  |                                 
|Net Income (Loss)                                                           |  | $                               
|                                                                            |  |                                 

|                                       |  | December 31,
|-------------------------------------- |  | ------------
|
|
|Balance Sheet Data:                    |  |             
|Current Assets                         |  | $           
|Property, Plant and Equipment, net     |  |             
|Deferred Debits and Other Assets       |  |             
|                                       |  |             
|Total Assets                           |  | $           
|                                       |  |             
|Current Liabilities                    |  | $           
|Long-Term Debt                         |  |             
|Deferred Credits and Other Liabilities |  |             
|Minority Interest                      |  |             
|Members' Equity                        |  |             
|                                       |  |             
|Total Liabilities and Members' Equity  |  | $           
|                                       |  |             

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

52

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Exelon

The information required by this Item is incorporated herein by reference to "Management's Discussion and Analysis of Financial Condition and Results of
Operations" in Exhibit 99-3 to Exelon's Current Report on Form 8-K dated February 21, 2003.

ComEd, PECO and Generation

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

Critical Accounting Estimates

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

Accounting for Derivative Instruments (ComEd, PECO and Generation)

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



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

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

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

53

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

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

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

A
derivative instrument can be designated as a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge) or a hedge of a
forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). To qualify for hedge accounting, the fair value changes in
the derivative must be expected to offset 80%-120% of the changes in fair value or cash flows of the hedged item. Changes in the fair value of a derivative that is designated and qualifies
as a fair value hedge and is highly effective, along with the gain or loss on the hedged asset or liability that is attributable to the hedged risk, are recorded in earnings. Changes in the fair value
of a derivative that is designated as and qualifies as a cash flow hedge and is highly effective, are recorded in OCI, until earnings are affected by the variability of cash flows being hedged. Exelon
continually assesses these cash flow hedges to determine if they continue to be effective and that the forecasted future transaction is probable. At the point in time that the contract does not meet
the effective or probable criteria of SFAS No. 133, hedge accounting is discontinued and the fair value of the derivative is recorded through earnings.

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

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

54

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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.

55

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

Regulatory Assets and Liabilities (ComEd and PECO)

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

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

The
most significant regulatory assets we have recorded are:



56

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

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

Nuclear Decommissioning (Generation)

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

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

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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

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

SFAS No. 143.The accounting for our nuclear decommissioning obligation will be affected by
the adoption of SFAS No. 143, "Asset Retirement Obligations" (SFAS No. 143) effective January 1, 2003. SFAS No. 143 provides accounting requirements for retirement
obligations associated with tangible long-lived assets. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for
which there is a legal obligation under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel.

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

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

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



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

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

Asset Impairments

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



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

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

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

Goodwill (ComEd).Under SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS
No. 142), goodwill is also subject to an assessment for impairment using a two-step fair value based test, the first step of which must be performed at least annually, or more
frequently if events or circumstances indicate that goodwill might be impaired. If an impairment is determined at ComEd, the amount of the impaired goodwill will be written-off and
expensed at ComEd.

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



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

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

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

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

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

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

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

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

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

|Change in Actuarial Assumption                 |  | Impact on
Projected Benefit
Obligation at
December 31, 2002 |     | Impact on
Pension Liability at
December 31, 2002 |   | Impact on
2003
Pension Cost
|---------------------------------------------- |  | ----------------------------------------------------------- | --- | ------------------------------------------------ | - | ---------------------------
|Pension Benefits                               |  |                                                             |     |                                                  |   |                            
|Decrease Discount Rate by 0.5%                 |  | $                                                           | 336 |                                                  | $ | 336                        
|Decrease Rate of Return on Plan Assets by 0.5% |  |                                                             |    |                                                  |   |                           

|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 |                                                                 | $ |                                          
|Decrease Rate of Return on Plan Assets by 0.5% |  |                                                                        |    |                                                                 |   |                                          

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

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

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

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

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

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

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

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

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

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

|           |  | 2002 |    | 2001 |   | 2000 | 
|---------- |  | ---- | -- | ---- | - | ---- | 
|ComEd      |  | $    | 13 |      | $ | 10   | 
|PECO       |  |      | 13 |      |   | 15   | 
|Generation |  |      | 15 |      |   | 9    | 

---

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

Business Combinations (ComEd, PECO and Generation)

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

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

Unbilled Energy Revenues (ComEd, PECO and Generation)

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

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

Environmental Costs (ComEd, PECO and Generation)

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

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

New Accounting Pronouncements

SFAS No. 143 (ComEd, PECO and Generation)

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

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

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

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

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

SFAS No. 146 (ComEd, PECO and Generation)

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

FIN No. 45 (ComEd, PECO and Generation)

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

FIN No. 46 (ComEd, PECO and Generation)

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

67

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ComEd

General

On October 20, 2000, ComEd became a 99.9% owned subsidiary of Exelon as a result of the transactions relating to the Merger. As a result of the Merger,
ComEd's consolidated financial information for the period after the Merger has a different cost basis than that of previous periods. Material variances caused by the different cost basis have been
disclosed where applicable.

Through
December 31, 2000, ComEd operated as a vertically integrated electric utility. During January 2001, Exelon undertook a restructuring to separate its generation and
other competitive businesses from its regulated energy delivery business. As part of the restructuring, the non-regulated operations and related assets and liabilities of ComEd were
transferred to separate subsidiaries of Exelon. As a result, beginning January 2001, the operations of ComEd principally consist of the purchase, transmission, distribution and sale of
electricity in northern Illinois. The restructuring has had a significant impact on all components of ComEd's results of operations. The estimated impact of the restructuring set forth herein reflects
the effects of removing the operations related to ComEd's nuclear generating stations and obtaining energy and capacity from Generation under the terms of the PPA for the year ended
December 31, 2000.

68

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Results of Operations

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

Significant Operating TrendsComEd

|                            |                                                                                                                                                               | 2002                              |       | 2001  |       | Variance |       | % Change |    
|--------------------------- | ------------------------------------------------------------------------------------------------------------------------------------------------------------- | --------------------------------- | ----- | ----- | ----- | -------- | ----- | -------- | ---
|OPERATING REVENUES          |                                                                                                                                                               | $                                 | 6,124 |       | $     | 6,206    |       | $        | (82
|OPERATING EXPENSES          |                                                                                                                                                               |                                   |       |       |       |          |       |          |    
|                            | Purchased Power                                                                                                                                               |                                   |       | 2,585 |       |          | 2,670 |          |    
|                            | Operating and Maintenance                                                                                                                                     |                                   |       | 964   |       |          | 981   |          |    
|                            | Depreciation and Amortization                                                                                                                                 |                                   |       | 522   |       |          | 665   |          |    
|                            | Taxes Other Than Income                                                                                                                                       |                                   |       | 287   |       |          | 296   |          |    
|                            |                                                                                                                                                               |                                   |       |       |       |          |       |          |    
|                            |                                                                                                                                                               | Total Operating Expense           |       |       | 4,358 |          |       | 4,612    |    
|                            |                                                                                                                                                               |                                   |       |       |       |          |       |          |    
|OPERATING INCOME            |                                                                                                                                                               |                                   | 1,766 |       |       | 1,594    |       |          | 172
|                            |                                                                                                                                                               |                                   |       |       |       |          |       |          |    
|OTHER INCOME AND DEDUCTIONS |                                                                                                                                                               |                                   |       |       |       |          |       |          |    
|                            | Interest Expense                                                                                                                                              |                                   |       | (484  | )     |          | (565  | )        |    
|                            | 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   |          |    
|                            |                                                                                                                                                               |                                   |       |       |       |          |       |          |    
|                            |                                                                                                                                                               | Total Other Income and Deductions |       |       | (470  | )        |       | (481     | )  
|                            |                                                                                                                                                               |                                   |       |       |       |          |       |          |    
|INCOME BEFORE INCOME TAXES  |                                                                                                                                                               |                                   | 1,296 |       |       | 1,113    |       |          | 183
|INCOME TAXES                |                                                                                                                                                               |                                   | 506   |       |       | 506      |       |          |   
|                            |                                                                                                                                                               |                                   |       |       |       |          |       |          |    
|NET INCOME                  |                                                                                                                                                               | $                                 | 790   |       | $     | 607      |       | $        | 183
|                            |                                                                                                                                                               |                                   |       |       |       |          |       |          |    

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.

69

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Operating Revenues

ComEd's electric sales statistics are as follows:

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

---

70

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|Electric Revenue                        |  | 2002 |       | 2001 |   | Variance |  | % Change |     
|--------------------------------------- |  | ---- | ----- | ---- | - | -------- |  | -------- | ----
|Bundled Revenues(1)                     |  |      |       |      |   |          |  |          |     
|Residential                             |  | $    | 2,381 |      | $ | 2,308    |  | $        | 73  
|Small Commercial & Industrial           |  |      | 1,736 |      |   | 1,821    |  |          | (85 
|Large Commercial & Industrial           |  |      | 410   |      |   | 523      |  |          | (113
|Public Authorities & Electric Railroads |  |      | 377   |      |   | 430      |  |          | (53 
|                                        |  |      |       |      |   |          |  |          |     
|                                        |  |      | 4,904 |      |   | 5,082    |  |          | (178
|                                        |  |      |       |      |   |          |  |          |     
|Unbundled Revenues(2)                   |  |      |       |      |   |          |  |          |     
|ARES                                    |  |      |       |      |   |          |  |          |     
|Small Commercial & Industrial           |  |      | 138   |      |   | 48       |  |          | 90  
|Large Commercial & Industrial           |  |      | 154   |      |   | 74       |  |          | 80  
|Public Authorities & Electric Railroads |  |      | 28    |      |   | 5        |  |          | 23  
|                                        |  |      |       |      |   |          |  |          |     
|                                        |  |      | 320   |      |   | 127      |  |          | 193 
|                                        |  |      |       |      |   |          |  |          |     
|PPO                                     |  |      |       |      |   |          |  |          |     
|Small Commercial & Industrial           |  |      | 204   |      |   | 220      |  |          | (16 
|Large Commercial & Industrial           |  |      | 278   |      |   | 343      |  |          | (65 
|Public Authorities & Electric Railroads |  |      | 71    |      |   | 59       |  |          | 12  
|                                        |  |      |       |      |   |          |  |          |     
|                                        |  |      | 553   |      |   | 622      |  |          | (69 
|                                        |  |      |       |      |   |          |  |          |     
|Total Unbundled Revenues                |  |      | 873   |      |   | 749      |  |          | 124 
|                                        |  |      |       |      |   |          |  |          |     
|Total Electric Retail Revenues          |  |      | 5,777 |      |   | 5,831    |  |          | (54 
|Wholesale and Miscellaneous Revenue(3)  |  |      | 347   |      |   | 375      |  |          | (28 
|                                        |  |      |       |      |   |          |  |          |     
|Total Electric Revenue                  |  | $    | 6,124 |      | $ | 6,206    |  | $        | (82 
|                                        |  |      |       |      |   |          |  |          |     

---

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 
|                |  |          |     

---

71

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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 
|Recoverable Transition Costs Amortization |  |      | 102 |      |   | 108      |  |          | (6  
|Other Amortization Expense                |  |      | 86  |      |   | 204      |  |          | (118
|                                          |  |      |     |      |   |          |  |          |     
|Total Depreciation and Amortization       |  | $    | 522 |      | $ | 665      |  | $        | (143
|                                          |  |      |     |      |   |          |  |          |     

72

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

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

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

Taxes Other Than Income

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

Interest Charges

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

Other Income and Deductions

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

Income Taxes

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

73

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

Summary Financial InformationComEd

|                                         |                                                                                                                                                               |   |                                   |       |   | Components of Variance |      
|---------------------------------------- | ------------------------------------------------------------------------------------------------------------------------------------------------------------- | - | --------------------------------- | ----- | - | ---------------------- | -----
|
|
|OPERATING REVENUES                       |                                                                                                                                                               | $ | 6,206                             |       | $ | 7,012                  |      
|                                         | Purchased Power and Fuel                                                                                                                                      |   |                                   | 2,670 |   |                        | 1,977
|                                         | Operating and Maintenance                                                                                                                                     |   |                                   | 981   |   |                        | 2,076
|                                         | Merger-Related Costs                                                                                                                                          |   |                                   |      |   |                        | 67   
|                                         | Depreciation and Amortization                                                                                                                                 |   |                                   | 665   |   |                        | 998  
|                                         | Taxes Other Than Income                                                                                                                                       |   |                                   | 296   |   |                        | 508  
|                                         |                                                                                                                                                               |   |                                   |       |   |                        |      
|                                         |                                                                                                                                                               |   | Total Operating Expenses          |       |   | 4,612                  |      
|                                         |                                                                                                                                                               |   |                                   |       |   |                        |      
|OPERATING INCOME                         |                                                                                                                                                               |   | 1,594                             |       |   | 1,386                  |      
|                                         |                                                                                                                                                               |   |                                   |       |   |                        |      
|OTHER INCOME AND DEDUCTIONS              |                                                                                                                                                               |   |                                   |       |   |                        |      
|                                         | Interest Expense                                                                                                                                              |   |                                   | (565  | ) |                        | (602 
|                                         | 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  
|                                         |                                                                                                                                                               |   |                                   |       |   |                        |      
|                                         |                                                                                                                                                               |   | Total Other Income and Deductions |       |   | (481                   | )    
|                                         |                                                                                                                                                               |   |                                   |       |   |                        |      
|INCOME BEFORE INCOME TAXES               |                                                                                                                                                               |   | 1,113                             |       |   | 1,062                  |      
|INCOME TAXES                             |                                                                                                                                                               |   | 506                               |       |   | 330                    |      
|                                         |                                                                                                                                                               |   |                                   |       |   |                        |      
|NET INCOME                               |                                                                                                                                                               |   | 607                               |       |   | 732                    |      
|Preferred and Preference Stock Dividends |                                                                                                                                                               |   |                                  |       |   | (3                     | )    
|                                         |                                                                                                                                                               |   |                                   |       |   |                        |      
|NET INCOME ON COMMON STOCK               |                                                                                                                                                               | $ | 607                               |       | $ | 729                    |      
|                                         |                                                                                                                                                               |   |                                   |       |   |                        |      

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.

74

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Operating Revenues

Bundled service reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the
transmission and distribution of the energy. Unbundled service reflects customers electing to receive electric generation service from the PPO or an ARES. Revenue from customers choosing the PPO
includes an energy charge at market rates, transmission and distribution charges and a CTC charge. Revenue from customers choosing an ARES includes a distribution charge and a CTC charge. Transmission
charges received from ARES are included in wholesale and miscellaneous revenue. ComEd's electric sales statistics are as follows:

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

---

75

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|Electric Revenue                        |                                        | 2001 |       | 2000 |   | Variance |    
|--------------------------------------- | -------------------------------------- | ---- | ----- | ---- | - | -------- | ---
|
|Bundled Revenue(1)                      |                                        |      |       |      |   |          |    
|Residential                             |                                        | $    | 2,308 |      | $ | 2,235    |    
|Small Commercial & Industrial           |                                        |      | 1,821 |      |   | 1,949    |    
|Large Commercial & Industrial           |                                        |      | 523   |      |   | 811      |    
|Public Authorities & Electric Railroads |                                        |      | 430   |      |   | 424      |    
|                                        |                                        |      |       |      |   |          |    
|                                        |                                        |      | 5,082 |      |   | 5,419    |    
|                                        |                                        |      |       |      |   |          |    
|Unbundled Revenue(2)                    |                                        |      |       |      |   |          |    
|ARES                                    |                                        |      |       |      |   |          |    
|Small Commercial & Industrial           |                                        |      | 48    |      |   | 62       |    
|Large Commercial & Industrial           |                                        |      | 74    |      |   | 115      |    
|Public Authorities & Electric Railroads |                                        |      | 5     |      |   | 7        |    
|                                        |                                        |      |       |      |   |          |    
|                                        |                                        |      | 127   |      |   | 184      |    
|                                        |                                        |      |       |      |   |          |    
|PPO                                     |                                        |      |       |      |   |          |    
|Small Commercial & Industrial           |                                        |      | 220   |      |   | 92       |    
|Large Commercial & Industrial           |                                        |      | 343   |      |   | 158      |    
|Public Authorities & Electric Railroads |                                        |      | 59    |      |   | 56       |    
|                                        |                                        |      |       |      |   |          |    
|                                        |                                        |      | 622   |      |   | 306      |    
|                                        |                                        |      |       |      |   |          |    
|                                        | Total Unbundled Revenues               |      |       | 749  |   |          | 490
|                                        |                                        |      |       |      |   |          |    
|Total Electric Retail Revenues          |                                        |      | 5,831 |      |   | 5,909    |    
|                                        | Wholesale and Miscellaneous Revenue(3) |      |       | 375  |   |          | 396
|                                        |                                        |      |       |      |   |          |    
|Total Electric Revenues                 |                                        | $    | 6,206 |      | $ | 6,305    |    
|                                        |                                        |      |       |      |   |          |    

---

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

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

76

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The
reduction in wholesale and miscellaneous revenues in 2001 as compared to 2000, as if the restructuring occurred on January 1, 2000, reflects a $101 million reduction in
off-system sales due to the expiration of wholesale contracts that were offered by ComEd from June 2000 to May 2001 to support the open access program in Illinois, partially
offset by a $58 million increase in transmission service revenue and the reversal of a $15 million reserve for revenue refunds to ComEd's municipal customers as a result of a favorable
FERC ruling.

Purchased Power and Fuel

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

Operating and Maintenance

O&M expense decreased $23 million, or 2%, compared to 2000, excluding the effects of restructuring. The decrease in O&M expense was primarily attributable
to a decrease in customer credit and billing costs due to process improvements and a decrease in storm restoration and service reliability costs, partially offset by higher administrative and general
costs.

Merger-Related Costs

Merger-related costs charged to expense in 2000 were $67 million consisting of $26 million of direct incremental costs and $41 million for
employee costs. Direct incremental costs represent expenses directly associated with completing the Merger, including professional fees, regulatory approval, and other merger integration costs.
Employee costs represent estimated severance payments provided for under Exelon's Merger Separation Plan for eligible employees whose positions were eliminated before October 20, 2000 due to
planned integration activities of the merged companies.

Depreciation and Amortization

Depreciation and amortization expense decreased $51 million, or 7%, compared to 2000, excluding the effects of restructuring. Regulatory asset and
decommissioning amortization decreased $180 million primarily due to the gain on the settlement of the common stock forward purchase arrangement in the

77

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first quarter of 2000, partially offset by a $103 million increase in goodwill amortization representing the impact of a full year of amortization expense in 2001 and a $26 million
increase in depreciation expense from increased plant in service due to continued transmission and distribution capital improvements. Consistent with the provisions of the Illinois legislation,
regulatory assets may be recovered at amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold. See ITEM 8. Financial Statements and
Supplementary DataComEd Note 5 of the Notes to Consolidated Financial Statements. Annual goodwill amortization of $126 million in 2001 was discontinued in 2002 upon the
adoption of SFAS No. 142.

Taxes Other Than Income

Taxes other than income decreased $81 million, or 21%, compared to 2000, excluding the effects of restructuring. The decrease in taxes other than income
was primarily attributable to the effect of the change in certain revenue taxes from operating revenue and tax expense to collections recorded as liabilities resulting from Illinois legislation.

Interest Charges

Interest charges consist of interest expense and distributions on Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts. Interest
charges increased $6 million, or 1%, compared to 2000, excluding the effects of restructuring. The increase in interest expense was primarily attributable to increased interest accrued on
estimated tax liabilities and interest due on amounts payable to affiliates.

Other Income and Deductions

Other income and deductions, excluding interest charges, decreased $194 million, compared to 2000. The decrease was primarily attributable to the
$113 million gain on the forward share purchase arrangement recognized during 2000 and a $115 million reduction in intercompany interest income in 2001 from Unicom
Investment, Inc., reflecting the impact of declining interest rates and an $850 million reduction in intercompany notes receivable in the fourth quarter of 2000, partially offset by the
$38 million loss on the sale of Cotter Corporation, a ComEd subsidiary, recognized during 2000.

Income Taxes

The effective income tax rate was 45.5% in 2001, compared to 31.1% in 2000. The increase in the effective tax rate was primarily attributable to the effects of
the gain on the forward share purchase arrangement recorded in 2000, which was not recognized for tax purposes, a full year of goodwill amortization in 2001, which is not deductible for tax purposes,
the amortization of certain recoverable transition costs, which is not deductible for tax purposes and lower investment tax credit amortization resulting from the application of purchase accounting in
connection with the Merger.

Liquidity and Capital Resources

ComEd's business is capital intensive and requires considerable capital resources. ComEd's capital resources are primarily provided by internally generated cash
flows from operations and, to the extent necessary, external financing including the issuance of commercial paper. ComEd's access to external financing at reasonable terms is dependent on its credit
ratings and general business conditions, as well as that of the utility industry in general. Capital resources are used primarily to fund ComEd's capital requirements, including construction,
repayments of maturing debt and the payment of dividends.

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Cash Flows from Operating Activities

Cash flows provided by operations in 2002 were $2.0 billion as compared to $1.3 billion in 2001. The increase in cash flows in 2002 was primarily
attributable to a $183 million increase in net income, a $175 million increase in other operating activities, and a $422 million increase in working capital partially offset by a
decrease of $143 million in depreciation and amortization. ComEd's future cash flows will depend upon the ability to achieve reductions in operating costs, the impact of the economy, weather,
and customer choice on its revenues. Although the amounts may vary from period to period as a result of uncertainties inherent in the business, ComEd expects to continue to provide a reliable and
steady source of internal cash flow from operations for the foreseeable future.

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

Cash Flows from Investing Activities

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

ComEd
estimates that it will spend approximately $720 million in total capital expenditures for 2003. Approximately two thirds of the budgeted 2003 expenditures are for continuing
efforts to further improve the reliability of its transmission and distribution systems. The remaining one third is for capital additions to support new business and customer growth. ComEd anticipates
that it will obtain financing, when necessary, through borrowings, the issuance of preferred securities, or capital contributions from Exelon. ComEd's proposed capital expenditures and other
investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Cash Flows from Financing Activities

Cash flows used in financing activities in 2002 were $1,231 million as compared to $1,006 million in 2001. Cash flows used in financing activities
were primarily attributable to debt service and payments of dividends to Exelon. ComEd's debt financing activities in 2002 reflected the issuance of $600 million of First Mortgage Bonds, the
issuance of $100 million of Illinois Development Finance Authority floating-rate Pollution Control Revenue Refunding Bonds, the retirement of $340 million of transitional
trust notes, the redemption of $600 million in First Mortgage Bonds with available cash, the payment at maturity of $200 million in First Mortgage Bonds, the payment at maturity of
$200 million in variable rate senior notes, the payment at maturity of $100 million of fixed-rate medium-term notes and the redemption of $100 million of
7.25% Illinois Development Finance Authority Pollution Control Revenue Refunding Bonds. As of December 31, 2002, ComEd had $123 million in short-term borrowings of which
$52 million has been classified as long-term debt. In 2001, ComEd's debt financing activities reflected the retirement of $340 million of transitional trust notes and the
redemption of $196 million in First Mortgage Bonds. ComEd paid a $470 million dividend to Exelon during 2002 compared to a $483 million dividend in 2001.

Credit Issues

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

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

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

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

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

ComEd's
access to the capital markets, including the commercial paper market, and its financing costs in those markets are dependent on its securities ratings. None of ComEd's borrowings
are subject to default or prepayment as a result of a downgrading of securities ratings although such a downgrading could increase interest charges under certain bank credit facilities. The following
table shows ComEd's securities ratings at December 31, 2002:

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

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

Under
PUHCA, ComEd can only pay dividends from retained or current earnings; however, the SEC has authorized ComEd to pay up to $500 million in dividends out of additional
paid-in capital, provided ComEd may not pay dividends out of paid-in capital after December 31, 2002 if its common equity is less than 30% of its total capitalization
(including transitional trust notes). ComEd is

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

Contractual Obligations and Commercial Commitments

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

|                                                                                                                                      |  |   |       | Payment due within |   |    
|------------------------------------------------------------------------------------------------------------------------------------- |  | - | ----- | ------------------ | - | ---
|
|
|
|Long-Term Debt                                                                                                                        |  | $ | 6,024 | (a)                | $ | 750
|Notes Payable                                                                                                                         |  |   | 71    |                    |   | 71 
|Operating Leases                                                                                                                      |  |   | 135   |                    |   | 22 
|Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding the Company's Subordinated Debt Securities |  |   | 350   |                    |   |   
|                                                                                                                                      |  |   |       |                    |   |    
|Total Contractual Obligations                                                                                                         |  | $ | 6,580 |                    | $ | 843
|                                                                                                                                      |  |   |       |                    |   |    

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

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



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

|                                     |  |   |     | Expiration within |   |    
|------------------------------------ |  | - | --- | ----------------- | - | ---
|
|
|
|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 |                   |   |   
|Surety Bonds(e)                      |  |   | 18  |                   |   | 18 
|                                     |  |   |     |                   |   |    
|Total Commercial Commitments         |  | $ | 434 |                   | $ | 334
|                                     |  |   |     |                   |   |    

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

Critical Accounting Estimates

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

Business Outlook and the Challenges in Managing Our Business

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

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

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

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

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

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

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

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

The
Agreement addresses, among other things:





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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Capital Markets / Financing Environment

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

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

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



89

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

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

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

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

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

Inflation affects ComEd through increased operating costs and increased capital costs for transmission and distribution plant. As a result of the rate freezes
imposed under the legislation in Illinois and price pressures due to competition, ComEd may not be able to pass the costs of inflation through to customers.

Other

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

ComEd's business is subject to extensive environmental regulation by local, state and Federal authorities. These laws and regulations affect the manner in which
ComEd conducts its operations and make its capital expenditures. ComEd is subject to liability under these laws for the costs of remediating environmental contamination of property now or formerly
owned by ComEd and of property contaminated by hazardous substances ComEd generated. Management believes that it has a
responsible environmental management and compliance program; however, ComEd has incurred and expects to incur significant costs related to environmental compliance and site remediation and
clean-up. Remediation activities associated with manufactured gas plant operations conducted by predecessor companies will be one source of such costs. Also, ComEd is currently involved in
a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.

As
of December 31, 2002, ComEd's reserve for environmental investigation and remediation costs was $101 million, exclusive of decommissioning liabilities. ComEd has accrued
and will continue to accrue amounts that management believes are prudent to cover these environmental liabilities, but ComEd cannot predict with any certainty whether these amounts will be sufficient
to cover ComEd's environmental liabilities. Management cannot predict whether ComEd will incur other significant

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

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

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

Insurance.ComEd, through Exelon, carries property damage and liability insurance for its properties and operations. As a
result of significant changes in the insurance marketplace, due in part to the September 11, 2001 terrorist acts, the available coverage and limits may be less than the amount of insurance
obtained in the past and the recovery for losses due to terrorists acts may be limited. Exelon is self-insured to the extent that any losses may exceed the amount of insurance maintained.

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

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

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

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

New Accounting Pronouncements

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

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PECO

General

On October 20, 2000, PECO became a wholly-owned subsidiary of Exelon as a result of the transactions relating to the Merger.

During
January 2001, Exelon undertook a restructuring to separate its generation and other competitive businesses from its regulated energy delivery business. As part of the
restructuring, the non-regulated operations and related assets and liabilities of PECO, representing the generation and enterprises business segments, were transferred to separate
subsidiaries of Exelon. As a result, beginning January 2001, the operations of PECO consist of its retail electricity distribution and transmission business in southeastern Pennsylvania and its
natural gas distribution business located in the Pennsylvania counties surrounding the City of Philadelphia. The estimated impact of the restructuring set forth herein reflects the effects of removing
the generation and enterprises operations and obtaining energy and capacity from Generation under the terms of the PPA for the year ended December 31, 2000.

Results of Operations

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

Significant Operating TrendsPECO

|                            |                                                                                                                                                           | 2002                              |       | 2001  |       | Variance |       | % Change |    
|--------------------------- | --------------------------------------------------------------------------------------------------------------------------------------------------------- | --------------------------------- | ----- | ----- | ----- | -------- | ----- | -------- | ---
|OPERATING REVENUES          |                                                                                                                                                           | $                                 | 4,333 |       | $     | 3,965    |       | $        | 368
|OPERATING EXPENSES          |                                                                                                                                                           |                                   |       |       |       |          |       |          |    
|                            | Purchased Power                                                                                                                                           |                                   |       | 1,669 |       |          | 1,352 |          |    
|                            | Fuel                                                                                                                                                      |                                   |       | 348   |       |          | 450   |          |    
|                            | Operating and Maintenance                                                                                                                                 |                                   |       | 523   |       |          | 587   |          |    
|                            | Depreciation and Amortization                                                                                                                             |                                   |       | 456   |       |          | 416   |          |    
|                            | Taxes Other Than Income                                                                                                                                   |                                   |       | 244   |       |          | 161   |          |    
|                            |                                                                                                                                                           |                                   |       |       |       |          |       |          |    
|                            |                                                                                                                                                           | Total Operating Expense           |       |       | 3,240 |          |       | 2,966    |    
|                            |                                                                                                                                                           |                                   |       |       |       |          |       |          |    
|OPERATING INCOME            |                                                                                                                                                           |                                   | 1,093 |       |       | 999      |       |          | 94 
|                            |                                                                                                                                                           |                                   |       |       |       |          |       |          |    
|OTHER INCOME AND DEDUCTIONS |                                                                                                                                                           |                                   |       |       |       |          |       |          |    
|                            | Interest Expense                                                                                                                                          |                                   |       | (370  | )     |          | (413  | )        |    
|                            | 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    |          |    
|                            |                                                                                                                                                           |                                   |       |       |       |          |       |          |    
|                            |                                                                                                                                                           | Total Other Income and Deductions |       |       | (348  | )        |       | (377     | )  
|                            |                                                                                                                                                           |                                   |       |       |       |          |       |          |    
|INCOME BEFORE INCOME TAXES  |                                                                                                                                                           |                                   | 745   |       |       | 622      |       |          | 123
|INCOME TAXES                |                                                                                                                                                           |                                   | 259   |       |       | 197      |       |          | 62 
|                            |                                                                                                                                                           |                                   |       |       |       |          |       |          |    
|NET INCOME                  |                                                                                                                                                           |                                   | 486   |       |       | 425      |       |          | 61 
|Preferred Stock Dividends   |                                                                                                                                                           |                                   | (8    | )     |       | (10      | )     |          | 2  
|                            |                                                                                                                                                           |                                   |       |       |       |          |       |          |    
|NET INCOME ON COMMON STOCK  |                                                                                                                                                           | $                                 | 478   |       | $     | 415      |       | $        | 63 
|                            |                                                                                                                                                           |                                   |       |       |       |          |       |          |    

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Net Income

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

Operating Revenue

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

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

---

|Electric Revenue                        |  | 2002 |       | 2001 |   | Variance |  | % Change |     
|--------------------------------------- |  | ---- | ----- | ---- | - | -------- |  | -------- | ----
|Bundled Revenue(1)                      |  |      |       |      |   |          |  |          |     
|Residential                             |  | $    | 1,338 |      | $ | 1,028    |  | $        | 310 
|Small Commercial & Industrial           |  |      | 865   |      |   | 682      |  |          | 183 
|Large Commercial & Industrial           |  |      | 1,086 |      |   | 929      |  |          | 157 
|Public Authorities & Electric Railroads |  |      | 79    |      |   | 72       |  |          | 7   
|                                        |  |      |       |      |   |          |  |          |     
|                                        |  |      | 3,368 |      |   | 2,711    |  |          | 657 
|                                        |  |      |       |      |   |          |  |          |     
|Unbundled Revenue(2)                    |  |      |       |      |   |          |  |          |     
|Residential                             |  |      | 145   |      |   | 235      |  |          | (90 
|Small Commercial & Industrial           |  |      | 21    |      |   | 81       |  |          | (60 
|Large Commercial & Industrial           |  |      | 16    |      |   | 64       |  |          | (48 
|Public Authorities & Electric Railroads |  |      |      |      |   | 1        |  |          | (1  
|                                        |  |      |       |      |   |          |  |          |     
|                                        |  |      | 182   |      |   | 381      |  |          | (199
|                                        |  |      |       |      |   |          |  |          |     
|Total Electric Retail Revenues          |  |      | 3,550 |      |   | 3,092    |  |          | 458 
|Wholesale and Miscellaneous Revenue(3)  |  |      | 234   |      |   | 219      |  |          | 15  
|                                        |  |      |       |      |   |          |  |          |     
|Total Electric Revenue                  |  | $    | 3,784 |      | $ | 3,311    |  | $        | 473 
|                                        |  |      |       |      |   |          |  |          |     

---

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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
|                        |  |          |    





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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   | 
|Revenue                                     |  | $    | 549    |      | $ | 654      | 

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
|             |  |          |     

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.

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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
|Depreciation Expense                       |  |      | 125 |      |   | 119      |  |          | 6 
|Other Amortization Expense                 |  |      | 23  |      |   | 26       |  |          | (3
|                                           |  |      |     |      |   |          |  |          |   
|Total Depreciation and Amortization        |  | $    | 456 |      | $ | 416      |  | $        | 40
|                                           |  |      |     |      |   |          |  |          |   

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.

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

Summary Financial InformationPECO

|                                                                                                                                                           |                               |                          |       |       |       | Components of Variance |      
|---------------------------------------------------------------------------------------------------------------------------------------------------------- | ----------------------------- | ------------------------ | ----- | ----- | ----- | ---------------------- | -----
|
|OPERATING REVENUES                                                                                                                                         |                               | $                        | 3,965 |       | $     | 5,950                  |      
|                                                                                                                                                           | Purchased Power and Fuel      |                          |       | 1,802 |       |                        | 2,127
|                                                                                                                                                           | Operating and Maintenance     |                          |       | 587   |       |                        | 1,791
|                                                                                                                                                           | Merger-Related Costs          |                          |       |      |       |                        | 248  
|                                                                                                                                                           | Depreciation and Amortization |                          |       | 416   |       |                        | 325  
|                                                                                                                                                           | Taxes Other Than Income       |                          |       | 161   |       |                        | 237  
|                                                                                                                                                           |                               |                          |       |       |       |                        |      
|                                                                                                                                                           |                               | Total Operating Expenses |       |       | 2,966 |                        |      
|                                                                                                                                                           |                               |                          |       |       |       |                        |      
|OPERATING INCOME                                                                                                                                           |                               |                          | 999   |       |       | 1,222                  |      
|                                                                                                                                                           |                               |                          |       |       |       |                        |      
|OTHER INCOME AND DEDUCTIONS                                                                                                                                |                               |                          |       |       |       |                        |      
|Interest Expense                                                                                                                                           |                               |                          | (413  | )     |       | (463                   | )    
|Distributions on Company-Obligated
Mandatorily Redeemable
Preferred Securities of a Partnership,
which holds Solely Subordinated Debentures of the Company |                               |                          | (10   | )     |       | (8                     | )    
|Equity in Earnings (Losses) of Unconsolidated Affiliates, net                                                                                              |                               |                          |      |       |       | (41                    | )    
|Other, Net                                                                                                                                                 |                               |                          | 46    |       |       | 41                     |      
|                                                                                                                                                           |                               |                          |       |       |       |                        |      
|INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE                                                                       |                               |                          | 622   |       |       | 751                    |      
|INCOME TAXES                                                                                                                                               |                               |                          | 197   |       |       | 268                    |      
|                                                                                                                                                           |                               |                          |       |       |       |                        |      
|NET INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE                                                                                    |                               |                          | 425   |       |       | 483                    |      
|CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE (net of income taxes)                                                                                |                               |                          |      |       |       | 24                     |      
|                                                                                                                                                           |                               |                          |       |       |       |                        |      
|NET INCOME                                                                                                                                                 |                               |                          | 425   |       |       | 507                    |      
|PREFERRED STOCK DIVIDENDS                                                                                                                                  |                               |                          | (10   | )     |       | (10                    | )    
|                                                                                                                                                           |                               |                          |       |       |       |                        |      
|NET INCOME ON COMMON STOCK                                                                                                                                 |                               | $                        | 415   |       | $     | 497                    |      
|                                                                                                                                                           |                               |                          |       |       |       |                        |      

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.

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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     | %)
|                                        |  |        |  |        |  |          |   |          |   

---

|Electric Revenue                        |  | 2001 |       | 2000 |   | Variance |  | % Change |     
|--------------------------------------- |  | ---- | ----- | ---- | - | -------- |  | -------- | ----
|Bundled Revenue(1)                      |  |      |       |      |   |          |  |          |     
|Residential                             |  | $    | 1,028 |      | $ | 1,113    |  | $        | (85 
|Small Commercial & Industrial           |  |      | 682   |      |   | 422      |  |          | 260 
|Large Commercial & Industrial           |  |      | 929   |      |   | 532      |  |          | 397 
|Public Authorities & Electric Railroads |  |      | 72    |      |   | 47       |  |          | 25  
|                                        |  |      |       |      |   |          |  |          |     
|                                        |  |      | 2,711 |      |   | 2,114    |  |          | 597 
|                                        |  |      |       |      |   |          |  |          |     
|Unbundled Revenue(2)                    |  |      |       |      |   |          |  |          |     
|Residential                             |  |      | 235   |      |   | 135      |  |          | 100 
|Small Commercial & Industrial           |  |      | 81    |      |   | 154      |  |          | (73 
|Large Commercial & Industrial           |  |      | 64    |      |   | 180      |  |          | (116
|Public Authorities & Electric Railroads |  |      | 1     |      |   | 11       |  |          | (10 
|                                        |  |      |       |      |   |          |  |          |     
|                                        |  |      | 381   |      |   | 480      |  |          | (99 
|                                        |  |      |       |      |   |          |  |          |     
|Total Electric Retail Revenues          |  |      | 3,092 |      |   | 2,594    |  |          | 498 
|Wholesale and Miscellaneous Revenue(3)  |  |      | 219   |      |   | 247      |  |          | (28 
|                                        |  |      |       |      |   |          |  |          |     
|Total Electric Revenue                  |  | $    | 3,311 |      | $ | 2,841    |  | $        | 470 
|                                        |  |      |       |      |   |          |  |          |     

---

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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
|                |  |          |    



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

|                   |  | 2001 |        | 2000 |   | Variance | 
|------------------ |  | ---- | ------ | ---- | - | -------- | 
|Deliveries in mmcf |  |      | 81,528 |      |   | 91,686   | 
|Revenue            |  | $    | 654    |      | $ | 532      | 

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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
|             |  |          |    

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 |   |    
|----------------------------- |  | - | ----- | ------------------ | - | ---
|
|
|
|Long-Term Debt                |  | $ | 5,644 |                    | $ | 689
|Notes Payable                 |  |   | 200   |                    |   | 200
|COMRPS                        |  |   | 128   |                    |   |   
|Operating Leases              |  |   | 20    |                    |   | 5  
|                              |  |   |       |                    |   |    
|Total Contractual Obligations |  | $ | 5,992 |                    | $ | 894
|                              |  |   |       |                    |   |    

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



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

|                                     |  |   |     | Expiration within |   |    
|------------------------------------ |  | - | --- | ----------------- | - | ---
|
|
|
|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 |                   |   |   
|Surety Bonds(e)                      |  |   | 46  |                   |   | 46 
|                                     |  |   |     |                   |   |    
|Total Commercial Commitments         |  | $ | 646 |                   | $ | 492
|                                     |  |   |     |                   |   |    

---

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Off-Balance Sheet Obligations

PECO is party to an agreement with a financial institution under which it can sell or finance with limited recourse an undivided interest, adjusted daily, in up
to $225 million of designated accounts receivable until November 2005. PECO entered into this agreement to diversify its funding sources at favorable floating interest rates. At
December 31, 2002, PECO had sold a $225 million interest in accounts receivable, consisting of a $164 million interest in accounts receivable, which PECO accounted for as a sale
under SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilitiesa Replacement of FASB Statement No. 125," and a
$61 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable. See ITEM 8. Financial Statements and Supplementary
DataPECO Note 8 of the Notes to Consolidated Financial Statements. PECO retains the servicing responsibility for these receivables. The Agreement requires PECO to maintain the
$225 million interest, which, if not met, requires cash, which would otherwise be received by PECO under this program, to be held in escrow until the requirement is met. At December 31,
2002 and 2001, PECO met this requirement.

Critical Accounting Estimates

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

Business Outlook and the Challenges in Managing Our Business

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

PECO
has been authorized by the PUC to recover stranded costs of $5.3 billion ($4.6 billion of unamortized costs at December 31, 2002) over a twelve-year
period ending December 31, 2010, with a return on the unamortized balance of 10.75%. PECO's recovery of stranded costs is based on the level of transition charges established in the settlement
of PECO's restructuring case and the projected annual retail sales in PECO's service territory. Recovery of transition charges for stranded costs and PECO's allowed return on its recovery of stranded
costs are included in revenues. In 2002, revenue attributable to stranded cost recovery was $850 million and is scheduled to increase to $932 million by 2010, the final year of stranded
cost recovery. Amortization of PECO's stranded cost recovery, which is a regulatory asset, is included in depreciation and amortization. The amortization expense for 2002 was $308 million and
will increase to $879 million by 2010. Thus, PECO's results will be adversely affected over the remaining period ending December 31, 2010 by the reduction in the unamortized balance of
stranded costs and therefore the return received on that unamortized balance.

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

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

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

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

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

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

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

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

Capital Markets / Financing Environment

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

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

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



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

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

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

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

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

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

Other

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

PECO's business is subject to extensive environmental regulation by local, state and Federal authorities. These laws and regulations affect the manner in which
PECO conducts its operations and makes its capital expenditures. PECO is subject to liability under these laws for the costs of remediating environmental contamination of property now or formerly
owned by PECO and of property contaminated by hazardous substances PECO generated. Management believes that it has a responsible environmental management and compliance program; however, PECO has
incurred and expects to incur significant costs related to environmental compliance and site remediation and clean-up. Remediation activities associated with manufactured gas plant
operations will be one source of such costs. Also, PECO is currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to
additional proceedings in the future.

As
of December 31, 2002, PECO's reserve for environmental investigation and remediation costs was $40 million, exclusive of decommissioning liabilities. PECO has accrued
and will continue to accrue amounts that management believes are prudent to cover these environmental liabilities, but PECO cannot predict with any certainty whether these amounts will be sufficient
to cover PECO's environmental liabilities. Management cannot predict whether PECO will incur other significant liabilities for any additional investigation and remediation costs at additional sites
not currently identified by PECO, environmental agencies or others, or whether such costs will be recoverable from third parties.

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

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

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

Insurance.PECO, through Exelon, carries property damage and liability insurance for its properties and operations. As a
result of significant changes in the insurance marketplace, due in part to the September 11, 2001 terrorist acts, the available coverage and limits may be less than the amount of insurance
obtained in the past, and the recovery for losses due to terrorists acts may be limited. Exelon is self-insured to the extent that any losses may exceed the amount of insurance maintained.

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

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

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

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

New Accounting Pronouncements

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

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Generation

General

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

Results of Operations

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

Significant Operating TrendsGeneration

|                                                                                     |                                                               | 2002                              |       | 2001  |       | Variance |       | % Change |     
|------------------------------------------------------------------------------------ | ------------------------------------------------------------- | --------------------------------- | ----- | ----- | ----- | -------- | ----- | -------- | ----
|OPERATING REVENUES                                                                   |                                                               | $                                 | 6,858 |       | $     | 6,826    |       | $        | 32  
|OPERATING EXPENSES                                                                   |                                                               |                                   |       |       |       |          |       |          |     
|                                                                                     | Purchased Power                                               |                                   |       | 3,294 |       |          | 3,106 |          |     
|                                                                                     | Fuel                                                          |                                   |       | 959   |       |          | 889   |          |     
|                                                                                     | Operating and Maintenance                                     |                                   |       | 1,656 |       |          | 1,528 |          |     
|                                                                                     | Depreciation                                                  |                                   |       | 276   |       |          | 282   |          |     
|                                                                                     | Taxes Other Than Income                                       |                                   |       | 164   |       |          | 149   |          |     
|                                                                                     |                                                               |                                   |       |       |       |          |       |          |     
|                                                                                     |                                                               | Total Operating Expense           |       |       | 6,349 |          |       | 5,954    |     
|                                                                                     |                                                               |                                   |       |       |       |          |       |          |     
|OPERATING INCOME                                                                     |                                                               |                                   | 509   |       |       | 872      |       |          | (363
|                                                                                     |                                                               |                                   |       |       |       |          |       |          |     
|OTHER INCOME AND DEDUCTIONS                                                          |                                                               |                                   |       |       |       |          |       |          |     
|                                                                                     | Interest Expense                                              |                                   |       | (75   | )     |          | (115  | )        |     
|                                                                                     | Equity in Earnings (Losses) of Unconsolidated Affiliates, net |                                   |       | 87    |       |          | 90    |          |     
|                                                                                     | Other, Net                                                    |                                   |       | 83    |       |          | (8    | )        |     
|                                                                                     |                                                               |                                   |       |       |       |          |       |          |     
|                                                                                     |                                                               | Total Other Income and Deductions |       |       | 95    |          |       | (33      | )   
|                                                                                     |                                                               |                                   |       |       |       |          |       |          |     
|INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES |                                                               |                                   | 604   |       |       | 839      |       |          | (235
|INCOME TAXES                                                                         |                                                               |                                   | 217   |       |       | 327      |       |          | (110
|                                                                                     |                                                               |                                   |       |       |       |          |       |          |     
|INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES                  |                                                               |                                   | 387   |       |       | 512      |       |          | (125
|CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES, (net of income taxes)         |                                                               |                                   | 13    |       |       | 12       |       |          | 1   
|                                                                                     |                                                               |                                   |       |       |       |          |       |          |     
|NET INCOME                                                                           |                                                               | $                                 | 400   |       | $     | 524      |       | $        | (124
|                                                                                     |                                                               |                                   |       |       |       |          |       |          |     

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      | % 
|                                    |  |         |  |         |  |          |   

---

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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
|                                                    | Exelon Energy                         |      |       | 44.87 |   |          | 41.53
|                                                    | Market Sales                          |      |       | 30.75 |   |          | 37.00
|                                                    | Totalexcluding the trading portfolio |      |       | 32.68 |   |          | 34.51
|Average Supply Cost (1)excluding trading portfolio |                                       | $    | 20.14 |       | $ | 20.26    |      
|Average Marginexcluding the trading portfolio      |                                       | $    | 12.54 |       | $ | 14.25    |      

---

|                                                              |  | 2002 |       | 2001 |  
|------------------------------------------------------------- |  | ---- | ----- | ---- | -
|Nuclear fleet capacity factor (1)                             |  |      | 92.7  | %    |  
|Nuclear fleet production cost per MWh                         |  | $    | 13.00 |      | $
|Average purchased power cost for wholesale operations per MWh |  | $    | 41.83 |      | $

---

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 |      
|------------------------------------------------------------------------------------- | ---------------------------------------------------- | --------------------------------- | ----- | ----- | ----- | ----- | ----- | ---------------------- | -----
|
|OPERATING REVENUES                                                                    |                                                      | $                                 | 6,826 |       | $     | 3,274 |       | $                      | 3,552
|OPERATING EXPENSES                                                                    |                                                      |                                   |       |       |       |       |       |                        |      
|                                                                                      | Purchased Power and Fuel                             |                                   |       | 3,995 |       |       | 1,846 |                        |      
|                                                                                      | Operating & Maintenance                              |                                   |       | 1,528 |       |       | 800   |                        |      
|                                                                                      | Depreciation                                         |                                   |       | 282   |       |       | 123   |                        |      
|                                                                                      | Taxes Other Than Income                              |                                   |       | 149   |       |       | 64    |                        |      
|                                                                                      |                                                      |                                   |       |       |       |       |       |                        |      
|                                                                                      |                                                      | Total Operating Expenses          |       |       | 5,954 |       |       | 2,833                  |      
|OPERATING INCOME                                                                      |                                                      |                                   | 872   |       |       | 441   |       |                        | 431  
|                                                                                      |                                                      |                                   |       |       |       |       |       |                        |      
|OTHER INCOME AND DEDUCTIONS                                                           |                                                      |                                   |       |       |       |       |       |                        |      
|                                                                                      | Interest expense                                     |                                   |       | (115  | )     |       | (41   | )                      |      
|                                                                                      | Equity in Earnings of Unconsolidated Affiliates, net |                                   |       | 90    |       |       | 4     |                        |      
|                                                                                      | Other, Net                                           |                                   |       | (8    | )     |       | 16    |                        |      
|                                                                                      |                                                      |                                   |       |       |       |       |       |                        |      
|                                                                                      |                                                      | Total Other Income and Deductions |       |       | (33   | )     |       | (21                    | )    
|INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECTS OF CHANGES IN ACCOUNTING PRINCIPLES |                                                      |                                   | 839   |       |       | 420   |       |                        | 419  
|INCOME TAXES                                                                          |                                                      |                                   | 327   |       |       | 160   |       |                        | 167  
|                                                                                      |                                                      |                                   |       |       |       |       |       |                        |      
|INCOME BEFORE CUMULATIVE EFFECTS OF CHANGES IN ACCOUNTING PRINCIPLES                  |                                                      |                                   | 512   |       |       | 260   |       |                        | 252  
|CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (net of income taxes)           |                                                      |                                   | 12    |       |       |      |       |                        | 12   
|                                                                                      |                                                      |                                   |       |       |       |       |       |                        |      
|NET INCOME                                                                            |                                                      | $                                 | 524   |       | $     | 260   |       | $                      | 264  
|                                                                                      |                                                      |                                   |       |       |       |       |       |                        |      

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 |   |      
|---------------------------------- |  | - | ------ | ------------------ | - | -----
|
|
|
|Long-Term Debt                     |  | $ | 2,137  |                    | $ | 5    
|Short-Term Note to Sithe           |  |   | 534    |                    |   | 534  
|Note Payable to Exelon Corporation |  |   | 329    |                    |   | 329  
|Operating Leases                   |  |   | 592    |                    |   | 32   
|Purchased Power Obligations        |  |   | 14,729 |                    |   | 2,677
|Spent Nuclear Fuel Obligations     |  |   | 858    |                    |   |     
|                                   |  |   |        |                    |   |      
|Total Contractual Obligations      |  | $ | 19,179 |                    | $ | 3,577
|                                   |  |   |        |                    |   |      

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



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 |   |    
|--------------------------------------- |  | - | --- | ----------------- | - | ---
|
|
|Credit Facility(a)                      |  | $ |    |                   | $ |   
|Letters of Credit (non-debt)(b)         |  |   | 11  |                   |   | 6  
|Letters of Credit (Long-Term Debt)(c)   |  |   | 346 |                   |   | 195
|Performance Guarantees(d)               |  |   | 101 |                   |   |   
|Surety Bonds(e)                         |  |   | 43  |                   |   |   
|Energy Marketing Contract Guarantees(f) |  |   | 1   |                   |   | 1  
|Nuclear Insurance Guarantee(g)          |  |   | 134 |                   |   |   
|Sithe New England Equity Guarantee(h)   |  |   | 38  |                   |   | 38 
|                                        |  |   |     |                   |   |    
|Total Commercial Commitments            |  | $ | 674 |                   | $ | 240
|                                        |  |   |     |                   |   |    

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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.

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

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

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

If
Generation increases its ownership in Sithe to 50.1% or more, Sithe may become a consolidated subsidiary and Generation's financial results may include Sithe's financial results from
the date of purchase. At December 31, 2002, Sithe had total assets of $2.6 billion and total debt of $1.3 billion. This $1.3 billion includes $624 million of
subsidiary debt incurred primarily to finance the construction of six 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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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:



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
|                                                                  | Changes in Valuation Techniques and Assumptions         |                                             |       |                    |   |       |   
|                                                                  | Reclassification to Realized at Settlement of Contracts |                                             |       | (20                 | ) |       | 20 
|                                                                  |                                                         |                                             |       |                     |   |       |    
|                                                                  | Total Change in Unrealized Fair Value                   |                                             |       | 6                   |   |       | (9 
|Realized Net Settlement of Transactions Subject to Mark-to-Market |                                                         |                                             | 20    |                     |   | (20   | )  
|                                                                  |                                                         |                                             |       |                     |   |       |    
|Total Mark-to-Market Activities Gross Margin                      |                                                         | $                                           | 26    |                     | $ | (29   | )  
|                                                                  |                                                         |                                             |       |                     |   |       |    
|Accrual Activities:                                               |                                                         |                                             |       |                     |   |       |    
|Accrual Activities Revenue                                        |                                                         | $                                           | 6,785 |                     | $ |      |    
|Hedge Gains/(Losses) Reclassified from OCI                        |                                                         |                                             | 76    |                     |   |      |    
|                                                                  |                                                         |                                             |       |                     |   |       |    
|                                                                  | Total RevenueAccrual Activities                        |                                             |       | 6,861               |   |       |   
|                                                                  |                                                         |                                             |       |                     |   |       |    
|Purchased Power and Fuel                                          |                                                         |                                             | 4,230 |                     |   |      |    
|Hedges of Purchased Power and Fuel Reclassified from OCI          |                                                         |                                             | 23    |                     |   |      |    
|                                                                  |                                                         |                                             |       |                     |   |       |    
|                                                                  | Total Purchased Power and Fuel                          |                                             |       | 4,253               |   |       |   
|                                                                  |                                                         |                                             |       |                     |   |       |    
|                                                                  | Total Accrual Activities Gross Margin                   |                                             |       | 2,608               |   |       |   
|                                                                  |                                                         |                                             |       |                     |   |       |    
|Total Gross Margin                                                |                                                         | $                                           | 2,634 |                     | $ | (29   | )  
|                                                                  |                                                         |                                             |       |                     |   |       |    

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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    |  
|Total Change in Fair Value during 2002 of Contracts Recorded in Earnings           |  |                                          | 26   |                     |   | (29   | )
|Reclassification to Realized at Settlement of Contracts Recorded in Earnings       |  |                                          | (20  | )                   |   | 20    |  
|Reclassification to Realized at Settlement from OCI                                |  |                                          | (53  | )                   |   |      |  
|Effective Portion of Changes in Fair ValueRecorded in OCI                         |  |                                          | (210 | )                   |   |      |  
|Purchase/Sale of Existing Contracts or Portfolios Subject to Mark-to-Market        |  |                                          | 11   |                     |   |      |  
|                                                                                   |  |                                          |      |                     |   |       |  
|Total Mark-to-Market Energy Contract Net Assets (Liabilities) at December 31, 2002 |  | $                                        | (168 | )                   | $ | 5     |  
|                                                                                   |  |                                          |      |                     |   |       |  

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     |   
|Noncurrent Assets                                             |                                                  |                                          | 46   |                     |   |      |   
|                                                              |                                                  |                                          |      |                     |   |       |   
|                                                              | Total Mark-to-Market Energy Contract Assets      |                                          |      | 232                 |   |       | 6 
|                                                              |                                                  |                                          |      |                     |   |       |   
|Current Liabilities                                           |                                                  |                                          | (276 | )                   |   |      |   
|Noncurrent Liabilities                                        |                                                  |                                          | (124 | )                   |   | (1    | ) 
|                                                              |                                                  |                                          |      |                     |   |       |   
|                                                              | Total Mark-to-Market Energy Contract Liabilities |                                          |      | (400                | ) |       | (1
|                                                              |                                                  |                                          |      |                     |   |       |   
|Total Mark-to-Market Energy Contract Net Assets (Liabilities) |                                                  | $                                        | (168 | )                   | $ | 5     |   
|                                                              |                                                  |                                          |      |                     |   |       |   

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 |   |      |  
|----------------------------------------------------------- | ------------------------------------------------ | ----------------- | - | ---- | -
|
|Normal Operations, qualifying cash flow hedge contracts(1): |                                                  |                   |   |      |  
|                                                            | Prices provided by other external sources        |                   | $ | (124 | )
|                                                            |                                                  |                   |   |      |  
|                                                            | Total                                            |                   | $ | (124 | )
|                                                            |                                                  |                   |   |      |  
|Normal Operations, other derivative contracts(2):           |                                                  |                   |   |      |  
|                                                            | Actively quoted prices                           |                   | $ | 26   |  
|                                                            | Prices provided by other external sources        |                   |   |     |  
|                                                            | Prices based on model or other valuation methods |                   |   | 7    |  
|                                                            |                                                  |                   |   |      |  
|                                                            | Total                                            |                   | $ | 33   |  
|                                                            |                                                  |                   |   |      |  
|Proprietary Trading, other derivative contracts(3):         |                                                  |                   |   |      |  
|                                                            | Actively quoted prices                           |                   | $ | (4   | )
|                                                            | Prices provided by other external sources        |                   |   | 6    |  
|                                                            | Prices based on model or other valuation methods |                   |   | 5    |  
|                                                            |                                                  |                   |   |      |  
|                                                            | Total                                            |                   | $ | 7    |  
|                                                            |                                                  |                   |   |      |  
|Average tenor of proprietary trading portfolio(4)           |                                                  |                   |   |      |  
|                                                            |                                                  |                   |   |      |  

---

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 |     
|----------------------------------------------------------- |  | ---------------------------------------------------------------------------- | ----
|
|Accumulated OCI, January 1, 2002                            |  | $                                                                            | 47  
|Changes in Fair Value                                       |  |                                                                              | (128
|Reclassifications from OCI to Net Income                    |  |                                                                              | (33 
|                                                            |  |                                                                              |     
|Accumulated OCI Derivative Gain/(Loss) at December 31, 2002 |  | $                                                                            | (114
|                                                            |  |                                                                              |     

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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             |                        
|                                                         | Average for the Period |                        
|                                                         | High                   |                        
|                                                         | Low                    |                        
|95% Confidence Level, Ten-Day Holding Period, Two-Tailed |                        |                        
|                                                         | Period End             |                        
|                                                         | Average for the Period |                        
|                                                         | High                   |                        
|                                                         | Low                    |                        
|99% Confidence Level, One-Day Holding Period, Two-Tailed |                        |                        
|                                                         | Period End             |                        
|                                                         | Average for the Period |                        
|                                                         | High                   |                        
|                                                         | Low                    |                        

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

141

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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 |                                                                
|Split Rating         |                                       |                                         |    |                   |   |             |   |                                                           |    |                                                                
|Non-Investment Grade |                                       |                                         | 17  |                   |   | 11           |   |                                                           | 6   |                                                                
|No External Ratings  |                                       |                                         |     |                   |   |              |   |                                                           |     |                                                                
|                     | Internally RatedInvestment Grade     |                                         |     | 27                |   |              | 4 |                                                           |     | 23                                                             
|                     | Internally RatedNon-Investment Grade |                                         |     | 4                 |   |              | 2 |                                                           |     | 2                                                              
|                     |                                       |                                         |     |                   |   |              |   |                                                           |     |                                                                
|Total                |                                       | $                                       | 204 |                   | $ | 17           |   | $                                                         | 187 |                                                                
|                     |                                       |                                         |     |                   |   |              |   |                                                           |     |                                                                

|                     |                                       | Maturity of Credit Risk Exposure
|-------------------- | ------------------------------------- | --------------------------------
|
|Investment Grade     |                                       | $                               
|Split Rating         |                                       |                                 
|Non-Investment Grade |                                       |                                 
|No External Ratings  |                                       |                                 
|                     | Internally RatedInvestment Grade     |                                 
|                     | Internally RatedNon-Investment Grade |                                 
|                     |                                       |                                 
|Total                |                                       | $                               
|                     |                                       |                                 

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

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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

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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

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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

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Commonwealth Edison Company and Subsidiary Companies  Consolidated Statements of Income

|                                         |                                                              |                                   |       |       |      | For the periods |      
|---------------------------------------- | ------------------------------------------------------------ | --------------------------------- | ----- | ----- | ---- | --------------- | -----
|
|
|
|Operating Revenues                       |                                                              |                                   |       |       |      |                 |      
|                                         | Operating Revenues                                           |                                   | $     | 6,061 |      | $               | 6,125
|                                         | Operating Revenues from Affiliates                           |                                   |       | 63    |      |                 | 81   
|                                         |                                                              |                                   |       |       |      |                 |      
|Total Operating Revenues                 |                                                              |                                   | 6,124 |       |      | 6,206           |      
|                                         |                                                              |                                   |       |       |      |                 |      
|Operating Expenses                       |                                                              |                                   |       |       |      |                 |      
|                                         | Purchased Power and Fuel                                     |                                   |       | 26    |      |                 | 14   
|                                         | Purchased Power from Affiliate                               |                                   |       | 2,559 |      |                 | 2,656
|                                         | Operating and Maintenance                                    |                                   |       | 828   |      |                 | 846  
|                                         | Operating and Maintenance from Affiliates                    |                                   |       | 136   |      |                 | 135  
|                                         | Merger-Related Costs                                         |                                   |       |      |      |                 |     
|                                         | Depreciation and Amortization                                |                                   |       | 522   |      |                 | 665  
|                                         | Taxes Other Than Income                                      |                                   |       | 287   |      |                 | 296  
|                                         |                                                              |                                   |       |       |      |                 |      
|Total Operating Expenses                 |                                                              |                                   | 4,358 |       |      | 4,612           |      
|                                         |                                                              |                                   |       |       |      |                 |      
|Operating Income                         |                                                              |                                   | 1,766 |       |      | 1,594           |      
|                                         |                                                              |                                   |       |       |      |                 |      
|Other Income and Deductions              |                                                              |                                   |       |       |      |                 |      
|                                         | Interest Expense                                             |                                   |       | (480  | )    |                 | (555 
|                                         | Interest Expense from Affiliates                             |                                   |       | (4    | )    |                 | (10  
|                                         | Distributions on Company-Obligated Mandatorily               |                                   |       |       |      |                 |      
|                                         | Redeemable Preferred Securities of Subsidiary Trusts Holding |                                   |       |       |      |                 |      
|                                         | Solely the Company's Subordinated Debt Securities            |                                   |       | (30   | )    |                 | (30  
|                                         | Interest Income from Affiliates                              |                                   |       | 31    |      |                 | 79   
|                                         | Other, Net                                                   |                                   |       | 13    |      |                 | 35   
|                                         |                                                              |                                   |       |       |      |                 |      
|                                         |                                                              | Total Other Income and Deductions |       |       | (470 | )               |      
|                                         |                                                              |                                   |       |       |      |                 |      
|Income Before Income Taxes               |                                                              |                                   | 1,296 |       |      | 1,113           |      
|Income Taxes                             |                                                              |                                   | 506   |       |      | 506             |      
|                                         |                                                              |                                   |       |       |      |                 |      
|Net Income                               |                                                              |                                   | 790   |       |      | 607             |      
|Preferred and Preference Stock Dividends |                                                              |                                   |      |       |      |                |      
|                                         |                                                              |                                   |       |       |      |                 |      
|Net Income on Common Stock               |                                                              | $                                 | 790   |       | $    | 607             |      
|                                         |                                                              |                                   |       |       |      |                 |      

See Notes to Consolidated Financial Statements

146

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Commonwealth Edison Company and Subsidiary Companies  Consolidated Statements of Cash Flows

|                                                      |                                                    |                                                          |        |        |     | For the periods |     
|----------------------------------------------------- | -------------------------------------------------- | -------------------------------------------------------- | ------ | ------ | --- | --------------- | ----
|
|
|
|Cash Flows from Operating Activities                  |                                                    |                                                          |        |        |     |                 |     
|Net Income                                            |                                                    | $                                                        | 790    |        | $   | 607             |     
|Adjustments to reconcile Net Income to Net Cash Flows |                                                    |                                                          |        |        |     |                 |     
|provided by Operating Activities:                     |                                                    |                                                          |        |        |     |                 |     
|                                                      | Depreciation and Amortization                      |                                                          |        | 522    |     |                 | 665 
|                                                      | (Gain)/Loss on Forward Share Arrangements          |                                                          |        |       |     |                 |    
|                                                      | Reversal of Provision for Revenue Refunds          |                                                          |        |       |     |                 | (15 
|                                                      | Provision for Uncollectible Accounts               |                                                          |        | 50     |     |                 | 42  
|                                                      | Deferred Income Taxes                              |                                                          |        | 118    |     |                 | 14  
|                                                      | Merger-Related Costs                               |                                                          |        |       |     |                 |    
|                                                      | Early Retirement and Separation Program            |                                                          |        |       |     |                 |    
|                                                      | Midwest Independent System Operator Exit Fees      |                                                          |        |       |     |                 | (36 
|                                                      | Other Operating Activities                         |                                                          |        | (13    | )   |                 | (25 
|                                                      | Changes in Working Capital:                        |                                                          |        |        |     |                 |     
|                                                      |                                                    | Accounts Receivable                                      |        |        | (72 | )               |     
|                                                      |                                                    | Inventories                                              |        |        | (9  | )               |     
|                                                      |                                                    | Accounts Payable, Accrued Expenses & Current Liabilities |        |        | 135 |                 |     
|                                                      |                                                    | Change in Receivables and Payables to Affiliates, net    |        |        | 461 |                 |     
|                                                      |                                                    | Other Current Assets                                     |        |        | 1   |                 |     
|                                                      |                                                    |                                                          |        |        |     |                 |     
|Net Cash Flows provided by Operating Activities       |                                                    |                                                          | 1,983  |        |     | 1,346           |     
|                                                      |                                                    |                                                          |        |        |     |                 |     
|Cash Flows from Investing Activities                  |                                                    |                                                          |        |        |     |                 |     
|                                                      | Investment in Plant, net                           |                                                          |        | (780   | )   |                 | (869
|                                                      | Proceeds from Nuclear Decommissioning Trust Funds  |                                                          |        |       |     |                 |    
|                                                      | Investment in Nuclear Decommissioning Trust Funds  |                                                          |        |       |     |                 |    
|                                                      | Change in Receivables from Affiliates              |                                                          |        | 14     |     |                 | 400 
|                                                      | Other Investments                                  |                                                          |        |       |     |                 |    
|                                                      | Other Investing Activities                         |                                                          |        | 7      |     |                 | 11  
|                                                      |                                                    |                                                          |        |        |     |                 |     
|Net Cash Flows used in Investing Activities           |                                                    |                                                          | (759   | )      |     | (458            | )   
|                                                      |                                                    |                                                          |        |        |     |                 |     
|Cash Flows from Financing Activities                  |                                                    |                                                          |        |        |     |                 |     
|                                                      | Issuance of Long-Term Debt, net of issuance costs  |                                                          |        | 752    |     |                 |    
|                                                      | Common Stock Repurchases                           |                                                          |        |       |     |                 |    
|                                                      | Retirement of Long-Term Debt                       |                                                          |        | (1,551 | )   |                 | (542
|                                                      | Change in Short-Term Debt                          |                                                          |        | 71     |     |                 |    
|                                                      | Redemption of Preferred Securities of Subsidiaries |                                                          |        |       |     |                 |    
|                                                      | Change in Restricted Cash                          |                                                          |        | (24    | )   |                 | 19  
|                                                      | Dividends on Capital Stock                         |                                                          |        | (470   | )   |                 | (483
|                                                      | Common Stock Forward Repurchases                   |                                                          |        |       |     |                 |    
|                                                      | Nuclear Fuel Lease Principal Payments              |                                                          |        |       |     |                 |    
|                                                      | Other Financing Activities                         |                                                          |        | (9     | )   |                 |    
|                                                      |                                                    |                                                          |        |        |     |                 |     
|Net Cash Flow used in Financing Activities            |                                                    |                                                          | (1,231 | )      |     | (1,006          | )   
|                                                      |                                                    |                                                          |        |        |     |                 |     
|Increase (Decrease) in Cash and Cash Equivalents      |                                                    |                                                          | (7     | )      |     | (118            | )   
|Cash and Cash Equivalents at beginning of period      |                                                    |                                                          | 23     |        |     | 141             |     
|                                                      |                                                    |                                                          |        |        |     |                 |     
|Cash and Cash Equivalents at end of period            |                                                    | $                                                        | 16     |        | $   | 23              |     
|                                                      |                                                    |                                                          |        |        |     |                 |     

See Notes to Consolidated Financial Statements

147

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Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets

|                                                                                                                                      |                                                | December 31,                                 |       
|------------------------------------------------------------------------------------------------------------------------------------- | ---------------------------------------------- | -------------------------------------------- | ------
|
|
|Assets                                                                                                                                |                                               
|Current Assets                                                                                                                        |                                                |                                              |       
|                                                                                                                                      | Cash and Cash Equivalents                      |                                              | $     
|                                                                                                                                      | Restricted Cash                                |                                              |       
|                                                                                                                                      | Accounts Receivable, net                       |                                              |       
|                                                                                                                                      |                                                | Customer                                     |       
|                                                                                                                                      |                                                | Other                                        |       
|                                                                                                                                      | Inventories, at average cost                   |                                              |       
|Deferred Income Taxes                                                                                                                 |                                                |                                              | 20    
|                                                                                                                                      | Receivables from Affiliates                    |                                              |       
|                                                                                                                                      | Other                                          |                                              |       
|                                                                                                                                      |                                                |                                              |       
|                                                                                                                                      |                                                | Total Current Assets                         |       
|                                                                                                                                      |                                                |                                              |       
|Property, Plant and Equipment, net                                                                                                    |                                                |                                              | 7,744 
|Deferred Debits and Other Assets                                                                                                      |                                                |                                              |       
|                                                                                                                                      | Regulatory Assets                              |                                              |       
|                                                                                                                                      | Investments                                    |                                              |       
|                                                                                                                                      | Goodwill, net                                  |                                              |       
|                                                                                                                                      | Receivables from Affiliates                    |                                              |       
|                                                                                                                                      | Other                                          |                                              |       
|                                                                                                                                      |                                                |                                              |       
|                                                                                                                                      |                                                | Total Deferred Debits and Other Assets       |       
|                                                                                                                                      |                                                |                                              |       
|Total Assets                                                                                                                          |                                                | $                                            | 15,830
|                                                                                                                                      |                                                |                                              |       
|Liabilities and Shareholders' Equity                                                                                                  |                                               
|Current Liabilities                                                                                                                   |                                                |                                              |       
|Notes Payable                                                                                                                         |                                                | $                                            | 71    
|Long-Term Debt Due Within One Year                                                                                                    |                                                |                                              | 698   
|Accounts Payable                                                                                                                      |                                                |                                              | 201   
|Accrued Expenses                                                                                                                      |                                                |                                              | 477   
|Payables to Affiliates                                                                                                                |                                                |                                              | 416   
|Customer Deposits                                                                                                                     |                                                |                                              | 81    
|Other                                                                                                                                 |                                                |                                              | 79    
|                                                                                                                                      |                                                |                                              |       
|                                                                                                                                      |                                                | Total Current Liabilities                    |       
|                                                                                                                                      |                                                |                                              |       
|Long-Term Debt                                                                                                                        |                                                |                                              | 5,268 
|Deferred Credits and Other Liabilities                                                                                                |                                                |                                              |       
|                                                                                                                                      | Deferred Income Taxes                          |                                              |       
|                                                                                                                                      | Unamortized Investment Tax Credits             |                                              |       
|                                                                                                                                      | Pension Obligation                             |                                              |       
|                                                                                                                                      | Non-Pension Postretirement Benefits Obligation |                                              |       
|                                                                                                                                      | Payables to Affiliates                         |                                              |       
|                                                                                                                                      | Other                                          |                                              |       
|                                                                                                                                      |                                                |                                              |       
|                                                                                                                                      |                                                | Total Deferred Credits and Other Liabilities |       
|                                                                                                                                      |                                                |                                              |       
|Commitments and Contingencies                                                                                                         |                                                |                                              |       
|Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding the Company's Subordinated Debt Securities |                                                |                                              | 330   
|Shareholders' Equity                                                                                                                  |                                                |                                              |       
|                                                                                                                                      | Common Stock                                   |                                              |       
|                                                                                                                                      | Preference Stock                               |                                              |       
|                                                                                                                                      | Other Paid in Capital                          |                                              |       
|                                                                                                                                      | Receivable from Parent                         |                                              |       
|                                                                                                                                      | Retained Earnings                              |                                              |       
|                                                                                                                                      | Treasury Stock, at cost                        |                                              |       
|                                                                                                                                      | Accumulated Other Comprehensive Income, net    |                                              |       
|                                                                                                                                      |                                                |                                              |       
|                                                                                                                                      |                                                | Total Shareholders' Equity                   |       
|                                                                                                                                      |                                                |                                              |       
|Total Liabilities and Shareholders' Equity                                                                                            |                                                | $                                            | 15,830
|                                                                                                                                      |                                                |                                              |       

See Notes to Consolidated Financial Statements

148

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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 |  
|-------------------------------------------------------- |  | ------------ | ----- | ------------------------------ | - | --------------------- | - | ---------------------- | ------ | ----------------- | - | -------------------------------------- | - | -------------- | ---- | -------------------------- | -
|
|Balance, December 31, 1999                               |  | $            | 2,678 |                                | $ | 9                     |   | $                      | 2,211  |                   | $ |                                       |   | $              | 433  |                            | $
|Net Income                                               |  |              |      |                                |   |                      |   |                        |       |                   |   |                                       |   |                | 599  |                            |  
|Preferred and Preference Stock Redemptions               |  |              |      |                                |   | (2                    | ) |                        |       |                   |   |                                       |   |                |     |                            |  
|Capital Stock Expense                                    |  |              |      |                                |   |                      |   |                        |       |                   |   |                                       |   |                | (1   | )                          |  
|Common Stock Dividends                                   |  |              |      |                                |   |                      |   |                        |       |                   |   |                                       |   |                | (238 | )                          |  
|Preferred and Preference Stock Dividends                 |  |              |      |                                |   |                      |   |                        |       |                   |   |                                       |   |                | (1   | )                          |  
|Common Stock Repurchases                                 |  |              |      |                                |   |                      |   |                        |       |                   |   |                                       |   |                |     |                            |  
|Stock Forward Repurchase Contract                        |  |              |      |                                |   |                      |   |                        |       |                   |   |                                       |   |                |     |                            |  
|Other Comprehensive Income, net of income taxes of $0    |  |              |      |                                |   |                      |   |                        |       |                   |   |                                       |   |                |     |                            |  
|                                                         | 
|Balance, October 19, 2000                                |  |              | 2,678 |                                |   | 7                     |   |                        | 2,211  |                   |   |                                       |   |                | 792  |                            |  
|Net Income                                               |  |              |      |                                |   |                      |   |                        |       |                   |   |                                       |   |                | 133  |                            |  
|Merger Fair Value Adjustments                            |  |              |      |                                |   |                      |   |                        | 3,177  |                   |   |                                       |   |                | (792 | )                          |  
|Common Stock Repurchases                                 |  |              |      |                                |   |                      |   |                        |       |                   |   |                                       |   |                |     |                            |  
|                                                         |  |              |       |                                |   |                       |   |                        |        |                   |   |                                        |   |                |      |                            |  
|Balance, December 31, 2000                               |  |              | 2,678 |                                |   | 7                     |   |                        | 5,388  |                   |   |                                       |   |                | 133  |                            |  
|Net Income                                               |  |              |      |                                |   |                      |   |                        |       |                   |   |                                       |   |                | 607  |                            |  
|Receivable from Parent                                   |  |              |      |                                |   |                      |   |                        | 1,062  |                   |   | (1,062                                 | ) |                |     |                            |  
|Repayment of Receivable from Parent                      |  |              |      |                                |   |                      |   |                        |       |                   |   | 125                                    |   |                |     |                            |  
|Retirement of Treasury Shares                            |  |              | (630  | )                              |   |                      |   |                        | (1,393 | )                 |   |                                       |   |                |     |                            |  
|Merger Fair Value Adjustments                            |  |              |      |                                |   |                      |   |                        | 24     |                   |   |                                       |   |                |     |                            |  
|Corporate Restructuring                                  |  |              |      |                                |   |                      |   |                        | (24    | )                 |   |                                       |   |                |     |                            |  
|Common Stock Dividends                                   |  |              |      |                                |   |                      |   |                        |       |                   |   |                                       |   |                | (483 | )                          |  
|Other Comprehensive Income, net of income taxes of $(1)  |  |              |      |                                |   |                      |   |                        |       |                   |   |                                       |   |                |     |                            |  
|                                                         |  |              |       |                                |   |                       |   |                        |        |                   |   |                                        |   |                |      |                            |  
|Balance, December 31, 2001                               |  |              | 2,048 |                                |   | 7                     |   |                        | 5,057  |                   |   | (937                                   | ) |                | 257  |                            |  
|Net Income                                               |  |              |      |                                |   |                      |   |                        |       |                   |   |                                       |   |                | 790  |                            |  
|Repayment of Receivable from Parent                      |  |              |      |                                |   |                      |   |                        |       |                   |   | 322                                    |   |                |     |                            |  
|Allocation of Tax Benefit from Parent                    |  |              |      |                                |   |                      |   |                        | 28     |                   |   |                                       |   |                |     |                            |  
|Retirement of Treasury Shares                            |  |              | (460  | )                              |   |                      |   |                        | (884   | )                 |   |                                       |   |                |     |                            |  
|Merger Fair Value Adjustments                            |  |              |      |                                |   |                      |   |                        | 38     |                   |   |                                       |   |                |     |                            |  
|Common Stock Dividends                                   |  |              |      |                                |   |                      |   |                        |       |                   |   |                                       |   |                | (470 | )                          |  
|Other Comprehensive Income, net of income taxes of $(23) |  |              |      |                                |   |                      |   |                        |       |                   |   |                                       |   |                |     |                            |  
|                                                         |  |              |       |                                |   |                       |   |                        |        |                   |   |                                        |   |                |      |                            |  
|Balance, December 31, 2002                               |  | $            | 1,588 |                                | $ | 7                     |   | $                      | 4,239  |                   | $ | (615                                   | ) | $              | 577  |                            | $
|                                                         |  |              |       |                                |   |                       |   |                        |        |                   |   |                                        |   |                |      |                            |  

See Notes to Consolidated Financial Statements

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Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Comprehensive Income

|                                 |                                                        |   |     |     |   | For the Periods |    |   |    
|-------------------------------- | ------------------------------------------------------ | - | --- | --- | - | --------------- | -- | - | ---
|
|
|
|Net Income                       |                                                        | $ | 790 |     | $ | 607             |    | $ | 133
|Other Comprehensive Income       |                                                        |   |     |     |   |                 |    |   |    
|                                 | Cash Flow Hedge Fair Value Adjustment, net of          |   |     |     |   |                 |    |   |    
|                                 | income taxes of $(21) and $0, respectively             |   | $   | (30 | ) | $               | (1 | ) | $  
|                                 | Foreign Currency Translation Adjustment, net of        |   |     |     |   |                 |    |   |    
|                                 | income taxes of $0                                     |   |     |    |   |                 | (1 | ) |    
|                                 | Unrealized Gain (Loss) on Marketable Securities, net   |   |     |     |   |                 |    |   |    
|                                 | of income taxes of $(1), $(1), $0 and $0, respectively |   |     | (3  | ) |                 | (3 | ) |    
|                                 | Merger Fair Value Adjustment                           |   |     |    |   |                 |   |   |    
|                                 |                                                        |   |     |     |   |                 |    | I |    
|Total Other Comprehensive Income |                                                        |   | (33 | )   |   | (5              | )  |   | (6 
|                                 |                                                        |   |     |     |   |                 |    | I |    
|Total Comprehensive Income       |                                                        | $ | 757 |     | $ | 602             |    | $ | 127
|                                 |                                                        |   |     |     |   |                 |    | I |    

See
Notes to Consolidated Financial Statements

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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

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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
|-------------------------------------------------------- |  | - | --- |  | - | ---------------
|
|
|
|Net incomeas reported                                   |  | $ | 790 |  | $ | 607            
|Deduct: Total stock-based compensation expense           |  |   |     |  |   |                
|determined under fair value based method for all awards, |  |   |     |  |   |                
|net of income taxes                                      |  |   | 13  |  |   | 10             
|                                                         |  |   |     |  |   |                
|Pro forma net income                                     |  | $ | 777 |  | $ | 597            
|                                                         |  |   |     |  |   |                

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
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.

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 |   |      |  
|------------------------------------------------------- |  | - | --- | ----------- | - | ---- | -
|
|
|Employee severance payments                             |  | $ | 128 |             | $ | (64  | )
|Other benefits                                          |  |   | 21  |             |   | (13  | )
|                                                        |  |   |     |             |   |      |  
|Employee severance payments and other benefits          |  |   | 149 |             |   | (77  | )
|Actuarially determined pension and postretirement costs |  |   | 158 |             |   | (82  | )
|                                                        |  |   |     |             |   |      |  
|Unicom employee costComEd                              |  | $ | 307 |             | $ | (159 | )
|                                                        |  |   |     |             |   |      |  

---

158

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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  |  
|                                                                         |  |   |    

---

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
|                             |  |      

---

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.

159

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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
|----------------------------------- |  | ----------------------- | --- | --------------
|
|
|Reported net income on Common Stock |  | $                       | 790 |               
|Goodwill amortization               |  |                         |    |               
|                                    |  |                         |     |               
|Adjusted net income                 |  | $                       | 790 |               
|                                    |  |                         |     |               

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
|----------------------- |  | ------------------------------- | --- | --------------
|
|
|Taxes Other Than Income |  |                                 |     |               
|Utility(a)              |  | $                               | 205 |               
|Real Estate             |  |                                 | 20  |               
|Payroll                 |  |                                 | 28  |               
|Other                   |  |                                 | 34  |               
|                        |  |                                 |     |               
|Total                   |  | $                               | 287 |               
|                        |  |                                 |     |               

---



163

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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 |  
|----------------------------------------- |  | ------------------------------- | --- | -------------- | -
|
|
|Other, Net                                |  |                                 |     |                |  
|Investment Income                         |  | $                               | 11  |                | $
|Gain on forward share purchases           |  |                                 |    |                |  
|Gain (loss) on disposition of assets, net |  |                                 |    |                |  
|AFUDC, equity and borrowed                |  |                                 | 18  |                |  
|Reserve for potential plant disallowance  |  |                                 | (12 | )              |  
|Other income (expense)                    |  |                                 | (3  | )              |  
|                                          |  |                                 |     |                |  
|Total                                     |  | $                               | 14  |                | $
|                                          |  |                                 |     |                |  

Supplemental Cash Flow Information

|                                    |                                              | For the Year Ended
December 31, |     | For the period
|----------------------------------- | -------------------------------------------- | ------------------------------- | --- | --------------
|
|
|Cash paid during the year:          |                                              |                                 |     |               
|                                    | Interest (net of amount capitalized)         |                                 | $   | 417           
|                                    | Income taxes (net of refunds)                |                                 |     | 264           
|Non-cash investing and financing:   |                                              |                                 |     |               
|                                    | Common stock repurchase                      |                                 | $   |              
|                                    | Settlement of forward share                  |                                 |     |               
|                                    | repurchase arrangement                       |                                 |     |              
|                                    | Deferred tax on fossil plant sale            |                                 |     |              
|                                    | Net assets transferred as a result of the    |                                 |     |               
|                                    | corporate restructuring, net of note payable |                                 |     |              
|                                    | Contribution of receivable from parent       |                                 |     |              
|                                    | Resolution of certain tax matters and merger |                                 |     |               
|                                    | severance adjustments                        |                                 |     | 14            
|                                    | Purchase accounting estimate Adjustments     |                                 |     |              
|                                    | Regulatory asset fair value Adjustments      |                                 |     |              
|                                    | Retirement of treasury shares                |                                 |     | 1,344         
|Depreciation and amortization:      |                                              |                                 |     |               
|                                    | Property, plant and equipment                |                                 | $   | 358           
|                                    | Nuclear fuel                                 |                                 |     |              
|                                    | Regulatory assets                            |                                 |     | 164           
|                                    | Decommissioning                              |                                 |     |              
|                                    | Goodwill                                     |                                 |     |              
|                                    |                                              |                                 |     |               
|Total depreciation and amortization |                                              | $                               | 522 |               
|                                    |                                              |                                 |     |               

164

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Supplemental Balance Sheet Information

|                                                             |  | December 31,
|------------------------------------------------------------ |  | ------------
|
|Regulatory Assets                                            |  |             
|Nuclear decommissioning costs for retired plants             |  | $           
|Recoverable transition costs                                 |  |             
|Reacquired debt costs and interest rate swap settlements     |  |             
|Recoverable deferred income taxes (see Note 11Income Taxes) |  |             
|Other                                                        |  |             
|                                                             |  |             
|Total                                                        |  | $           
|                                                             |  |             

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,
|---------------- |  | ------------
|
|Accrued Expenses |  |             
|Accrued Expenses |  | $           
|Taxes Accrued    |  |             
|Interest Accrued |  |             
|                 |  |             
|Total            |  | $           
|                 |  |             

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 |      
|Construction Work in Progress        |                                     |                               | 373   |      
|Other Property, Plant and Equipment  |                                     |                               | 1,082 |      
|                                     |                                     |                               |       |      
|                                     | Total Property, Plant and Equipment |                               |       | 8,231
|                                     |                                     | Less Accumulated Depreciation |       |      
|                                     |                                     |                               |       |      
|Property, Plant and Equipment, net   |                                     | $                             | 7,744 |      
|                                     |                                     |                               |       |      

9. Notes Payable

|                                                |  | 2002 |      | 2001 |   | 2000 |  
|----------------------------------------------- |  | ---- | ---- | ---- | - | ---- | -
|Average borrowings                              |  | $    | 14   |      |  |      | $
|Average interest rates, computed on daily basis |  |      | 1.75 | %    |  |      |  
|Maximum borrowings outstanding                  |  | $    | 146  |      |  |      | $
|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, |          
|----------------------------------------- | ------------------------------------------ | ----------------- | ------------ | ------------ | ---------
|
|Securitized Long-Term Debt                |                                            |                   |              |              |          
|ComEd Transitional Trust Notes            |                                            |                   |              |              |          
|                                          | Series 1998-A:                             |                   | 5.39%-5.74%  |              | 2003-2008
|Other Long-Term Debt                      |                                            |                   |              |              |          
|First and Refunding Mortgage Bonds(a)(b): |                                            |                   |              |              |          
|                                          | Fixed rates                                |                   | 4.40%-9.875% |              | 2003-2023
|                                          | Floating rates                             |                   | 1.33%        |              | 2013     
|Notes payable                             |                                            |                   |              |              |          
|                                          | Fixed Rates                                |                   | 6.40%-9.20%  |              | 2004-2018
|                                          | Floating rates                             |                   | 2.03%        |              | 2003     
|Pollution control bonds:                  |                                            |                   |              |              |          
|                                          | Fixed rates                                |                   | 5.875%       |              | 2007     
|                                          | Floating rates                             |                   | 1.05%-1.50%  |              | 2009-2014
|Sinking fund debentures                   |                                            | 3.125%-4.75%      |              | 2004-2011    |          
|Commercial paper(c)                       |                                            | 1.69%             |              | 2003         |          
|                                          |                                            |                   |              |              |          
|Total Long-Term Debt(d)                   |                                            |                   |              |              |          
|                                          | Unamortized debt discount and premium, net |                   |              |              |          
|                                          | Fair value hedge carrying value adjustment |                   |              |              |          
|                                          | Due within one year                        |                   |              |              |          
|                                          |                                            |                   |              |              |          
|Long-Term Debt                            |                                            |                   |              |              |          
|                                          |                                            |                   |              |              |          

---

2003

$
7502004


5772005


8062006


7692007


526Thereafter


2,596Total

$
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 |  
|----------------------- | -------------------------- | ------------------------------- | --- | -------------- | -
|
|
|Included in operations: |                            |                                 |     |                |  
|Federal                 |                            |                                 |     |                |  
|                        | Current                    |                                 | $   | 308            |  
|                        | Deferred                   |                                 |     | 110            |  
|                        | Investment tax credit, net |                                 |     | (4             | )
|State                   |                            |                                 |     |                |  
|                        | Current                    |                                 |     | 80             |  
|                        | Deferred                   |                                 |     | 12             |  
|                        |                            |                                 |     |                |  
|                        |                            | $                               | 506 |                | $
|                        |                            |                                 |     |                |  

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 |     
|--------------------------- | --------------------------------------- | ------------------------------- | ---- | -------------- | ----
|
|
|U.S. Federal statutory rate |                                         | 35.0                            | %    | 35.0           | %   
|Increase (decrease) due to: |                                         |                                 |      |                |     
|                            | Plant basis differences                 |                                 | (1.3 | )              | 0.3 
|                            | State income taxes, net of              |                                 |      |                |     
|                            | Federal income tax benefit              |                                 | 4.6  |                | 5.5 
|                            | Amortization of goodwill                |                                 |     |                | 4.0 
|                            | Amortization of investment tax credit   |                                 | (0.3 | )              | (0.4
|                            | Amortization of regulatory asset        |                                 | 1.2  |                | 1.4 
|                            | Unrealized loss (gain) on forward share |                                 |      |                |     
|                            | repurchase arrangement                  |                                 |     |                |    
|                            | Other, net                              |                                 | (0.2 | )              | (0.3
|                            |                                         |                                 |      |                |     
|                            |                                         | 39.0                            | %    | 45.5           | %   
|                            |                                         |                                 |      |                |     

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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, |      
|------------------------------------------------ | ----------------------------------------------- | ------------ | -----
|
|Deferred tax liabilities:                        |                                                 |              |      
|                                                 | Plant basis difference                          |              | $    
|                                                 | Deferred investment tax credits                 |              |      
|                                                 | Deferred debt refinancing costs                 |              |      
|                                                 | Deferred gain on sale of plants                 |              |      
|                                                 |                                                 |              |      
|Total deferred tax liabilities                   |                                                 |              | 1,941
|                                                 |                                                 |              |      
|Deferred tax assets:                             |                                                 |              |      
|                                                 | Deferred pension and postretirement obligations |              |      
|                                                 | Other, net                                      |              |      
|                                                 |                                                 |              |      
|Total deferred tax assets                        |                                                 |              | (260 
|                                                 |                                                 |              |      
|Deferred income taxes (net) on the balance sheet |                                                 | $            | 1,681
|                                                 |                                                 |              |      

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

170

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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,
|--------------------------------------------------- |  | ------------
|
|
|Without mandatory redemption                        |  |             
|Preference stock, non-cumulative, without par value |  | 1,120       
|                                                    |  |             
|Total preferred and preference stock                |  | 1,120       
|                                                    |  |             

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, |          
|-------------------- | ----- | ---- |  | ---- | - | - | ----- | ------------ | ---------
|
|
|
|ComEd Financing I    |       | 2035 |  | 8.48 | % | $ | 25    |              | 8,000,000
|ComEd Financing II   |       | 2027 |  | 8.50 | % |   | 1,000 |              | 150,000  
|Unamortized Discount |       |      |  |      |   |   |       |              |          
|                     |       |      |  |      |   |   |       |              |          
|                     | Total |      |  |      |   |   |       |              |          
|                     |       |      |  |      |   |   |       |              |          

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   |  
|-------------------------------------------------- |  | ------------- | - | --------------- | - | ------- | -
|
|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  |  
|------------------------------------------------------------- | ------------------------------------------------------ | ---- | --- | ----- | -
|
|Non-derivatives:                                              |                                                        |      |     |       |  
|Liabilities                                                   |                                                        |      |     |       |  
|                                                              | Long-term debt (including amounts due within one year) |      | $   | 5,925 |  
|Company-Obligated Mandatorily Redeemable Preferred Securities |                                                        | $    | 330 |       | $
|Derivatives:                                                  |                                                        |      |     |       |  
|Fixed to floating interest rate swaps                         |                                                        | $    | 41  |       | $
|Forward interest rate swaps                                   |                                                        | $    | (52 | )     | $

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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 |   |    
|------------------------------------ |  | - | --- | ----------------- | - | ---
|
|
|
|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 |                   |   |   
|Surety Bonds(e)                      |  |   | 18  |                   |   | 18 
|                                     |  |   |     |                   |   |    
|Total Commercial Commitments         |  | $ | 434 |                   | $ | 334
|                                     |  |   |     |                   |   |    

---

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.

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

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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.

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 the settlement may be covered by insurance.

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,
|---------------------------------------- | ---------------------- | -------------------------------
|
|Operating Revenues from Affiliates       |                        |                                
|                                         | Generation(1)          |                                
|                                         | Enterprises(1)         |                                
|Purchased Power from Affiliate           |                        |                                
|                                         | PPA with Generation(2) |                                
|Operations & Maintenance from Affiliates |                        |                                
|                                         | BSC(3)                 |                                
|                                         | Enterprises(4,5)       |                                
|Interest Income from Affiliates          |                        |                                
|                                         | UII(6)                 |                                
|                                         | PECO(7)                |                                
|                                         | Generation(8)          |                                
|                                         | Other                  |                                
|Interest Expense from Affiliate          |                        |                                
|                                         | Generation(2,9)        |                                
|Capitalized costs                        |                        |                                
|                                         | BSC(3)                 |                                
|                                         | Enterprises(5)         |                                
|Cash Dividends Paid to Parent            |                        |                                

|                                                |                                           | December 31,
|----------------------------------------------- | ----------------------------------------- | ------------
|
|Receivables from Affiliates                     |                                           |             
|                                                | UII(6)                                    |             
|                                                | BSC(3,8)                                  |             
|Notes Receivable from Affiliates                |                                           |             
|                                                | UII(6)                                    |             
|                                                | Other                                     |             
|Payables to Affiliates                          |                                           |             
|                                                | Generation Decommissioning (10)           |             
|                                                | Generation(1,2,8)                         |             
|                                                | BSC(3,8)                                  |             
|                                                | Exelon Corporate(11)                      |             
|                                                | Other                                     |             
|Deferred Credits and Other Liabilities          |                                           |             
|                                                | Generation Decommissioning obligation(10) |             
|                                                | Other                                     |             
|Shareholders' EquityReceivable from Parent(12) |                                           |             

---

178

---

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
|------------ |  | ------------------ | ----- | ---------------- | - | ----------
|
|
|March 31     |  | $                  | 1,315 |                  | $ | 1,446     
|June 30      |  |                    | 1,481 |                  |   | 1,530     
|September 30 |  |                    | 1,938 |                  |   | 1,919     
|December 31  |  |                    | 1,390 |                  |   | 1,311     

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.

179

---

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.

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:





180

---









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.

181

---



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

182

---



PECO Energy Company and Subsidiary Companies  Consolidated Statements of Income

|                                                                                     |                                                                                                                                           | For the Years Ended December 31,  |      
|------------------------------------------------------------------------------------ | ----------------------------------------------------------------------------------------------------------------------------------------- | --------------------------------- | -----
|
|
|Operating Revenues                                                                   |                                                                                                                                           |                                   |      
|                                                                                     | Operating Revenues                                                                                                                        |                                   | $    
|                                                                                     | Operating Revenues from Affiliates                                                                                                        |                                   |      
|                                                                                     |                                                                                                                                           |                                   |      
|                                                                                     |                                                                                                                                           | Total Operating Revenues          |      
|                                                                                     |                                                                                                                                           |                                   |      
|Operating Expenses                                                                   |                                                                                                                                           |                                   |      
|                                                                                     | Purchased Power                                                                                                                           |                                   |      
|                                                                                     | Purchased Power from Affiliates                                                                                                           |                                   |      
|                                                                                     | Fuel                                                                                                                                      |                                   |      
|                                                                                     | Operating and Maintenance                                                                                                                 |                                   |      
|                                                                                     | Operating and Maintenance from Affiliates                                                                                                 |                                   |      
|                                                                                     | Merger-Related Costs                                                                                                                      |                                   |      
|                                                                                     | Depreciation and Amortization                                                                                                             |                                   |      
|                                                                                     | Taxes Other Than Income                                                                                                                   |                                   |      
|                                                                                     |                                                                                                                                           |                                   |      
|                                                                                     |                                                                                                                                           | Total Operating Expenses          |      
|                                                                                     |                                                                                                                                           |                                   |      
|Operating Income                                                                     |                                                                                                                                           |                                   | 1,093
|                                                                                     |                                                                                                                                           |                                   |      
|Other Income and Deductions                                                          |                                                                                                                                           |                                   |      
|                                                                                     | Interest Expense                                                                                                                          |                                   |      
|                                                                                     | Interest Expense from Affiliates                                                                                                          |                                   |      
|                                                                                     | Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership, which holds Solely Subordinated Debentures of the Company |                                   |      
|                                                                                     | Equity in Earnings (Losses) of Unconsolidated Affiliates                                                                                  |                                   |      
|                                                                                     | Interest Income from Affiliates                                                                                                           |                                   |      
|                                                                                     | Other, Net                                                                                                                                |                                   |      
|                                                                                     |                                                                                                                                           |                                   |      
|                                                                                     |                                                                                                                                           | Total Other Income and Deductions |      
|                                                                                     |                                                                                                                                           |                                   |      
|Income Before Income Taxes and Cumulative Effect of a Change in Accounting Principle |                                                                                                                                           |                                   | 745  
|Income Taxes                                                                         |                                                                                                                                           |                                   | 259  
|                                                                                     |                                                                                                                                           |                                   |      
|Income Before Cumulative Effect of a Change in Accounting Principle                  |                                                                                                                                           |                                   | 486  
|Cumulative Effect of a Change in Accounting Principle (net of income taxes of $16)   |                                                                                                                                           |                                   |     
|                                                                                     |                                                                                                                                           |                                   |      
|Net Income                                                                           |                                                                                                                                           |                                   | 486  
|Preferred Stock Dividends                                                            |                                                                                                                                           |                                   | 8    
|                                                                                     |                                                                                                                                           |                                   |      
|Net Income on Common Stock                                                           |                                                                                                                                           | $                                 | 478  
|                                                                                     |                                                                                                                                           |                                   |      

See
Notes to Consolidated Financial Statements

183

---

PECO Energy Company and Subsidiary Companies  Consolidated Statements of Cash Flows

|                                                                                        |                                                       | For the Years Ended December 31,                                            |                                                               
|--------------------------------------------------------------------------------------- | ----------------------------------------------------- | --------------------------------------------------------------------------- | --------------------------------------------------------------
|
|
|Cash Flows from Operating Activities                                                    |                                                       |                                                                             |                                                               
|Net Income                                                                              |                                                       | $                                                                           | 486                                                           
|Adjustments to reconcile Net Income to Net Cash Flows provided by Operating Activities: |                                                       |                                                                             |                                                               
|                                                                                        |                                                       | Depreciation and Amortization                                               |                                                               
|                                                                                        |                                                       | Cumulative Effect of a Change in Accounting Principle (net of income taxes) |                                                               
|                                                                                        |                                                       | Provision for Uncollectible Accounts                                        |                                                               
|                                                                                        |                                                       | Deferred Income Taxes                                                       |                                                               
|                                                                                        |                                                       | Merger-Related Costs                                                        |                                                               
|                                                                                        |                                                       | Deferred Energy Costs                                                       |                                                               
|                                                                                        |                                                       | Equity in (Earnings) Losses of Unconsolidated Affiliates                    |                                                               
|                                                                                        |                                                       | Other Operating Activities                                                  |                                                               
|                                                                                        |                                                       | Changes in Working Capital:                                                 |                                                               
|                                                                                        |                                                       |                                                                             | Accounts Receivable                                           
|                                                                                        |                                                       |                                                                             | Repurchase of Accounts Receivable                             
|                                                                                        |                                                       |                                                                             | Inventories                                                   
|                                                                                        |                                                       |                                                                             | Accounts Payable, Accrued Expenses & Other Current Liabilities
|                                                                                        |                                                       |                                                                             | Change in Receivables and Payables to Affiliates, net         
|                                                                                        |                                                       |                                                                             | Other Current Assets                                          
|                                                                                        |                                                       |                                                                             |                                                               
|Net Cash Flows provided by Operating Activities                                         |                                                       |                                                                             | 880                                                           
|                                                                                        |                                                       |                                                                             |                                                               
|Cash Flows from Investing Activities                                                    |                                                       |                                                                             |                                                               
|                                                                                        | Capital Expenditures                                  |                                                                             |                                                               
|                                                                                        | InfraSource, Inc. Acquisitions, net of cash acquired  |                                                                             |                                                               
|                                                                                        | Proceeds from Nuclear Decommissioning Trust Funds     |                                                                             |                                                               
|                                                                                        | Investment in Nuclear Decommissioning Trust Funds     |                                                                             |                                                               
|                                                                                        | Other Investing Activities                            |                                                                             |                                                               
|                                                                                        |                                                       |                                                                             |                                                               
|Net Cash Flows used in Investing Activities                                             |                                                       |                                                                             | (252                                                          
|                                                                                        |                                                       |                                                                             |                                                               
|Cash Flows from Financing Activities                                                    |                                                       |                                                                             |                                                               
|                                                                                        | Issuance of Long-Term Debt                            |                                                                             |                                                               
|                                                                                        | Common Stock Repurchases                              |                                                                             |                                                               
|                                                                                        | Retirement of Long-Term Debt                          |                                                                             |                                                               
|                                                                                        | Change in Receivable and Payable to Affiliates, net   |                                                                             |                                                               
|                                                                                        | Change in Short-Term Debt                             |                                                                             |                                                               
|                                                                                        | Redemptions of Mandatorily Redeemable Preferred Stock |                                                                             |                                                               
|                                                                                        | Change in Restricted Cash                             |                                                                             |                                                               
|                                                                                        | Dividends on Preferred and Common Stock               |                                                                             |                                                               
|                                                                                        | Proceeds from Employee Stock Plans                    |                                                                             |                                                               
|                                                                                        | Contribution from Parent                              |                                                                             |                                                               
|                                                                                        | Settlement of Interest Rate Swap Agreements           |                                                                             |                                                               
|                                                                                        | Other Financing Activities                            |                                                                             |                                                               
|                                                                                        |                                                       |                                                                             |                                                               
|Net Cash Flows provided by (used in) Financing Activities                               |                                                       |                                                                             | (597                                                          
|                                                                                        |                                                       |                                                                             |                                                               
|Increase in Cash and Cash Equivalents                                                   |                                                       |                                                                             | 31                                                            
|Cash Transferred in Restructuring                                                       |                                                       |                                                                             |                                                              
|Cash and Cash Equivalents at beginning of period                                        |                                                       |                                                                             | 32                                                            
|                                                                                        |                                                       |                                                                             |                                                               
|Cash and Cash Equivalents at end of period                                              |                                                       | $                                                                           | 63                                                            
|                                                                                        |                                                       |                                                                             |                                                               

See Notes to Consolidated Financial Statements

184

---



PECO Energy Company and Subsidiary Companies  Consolidated Balance Sheets

|                                                                                                                                          |                                                | December 31,                                 |       
|----------------------------------------------------------------------------------------------------------------------------------------- | ---------------------------------------------- | -------------------------------------------- | ------
|
|
|Assets                                                                                                                                    |                                                |                                              |       
|Current Assets                                                                                                                            |                                                |                                              |       
|                                                                                                                                          | Cash and Cash Equivalents                      |                                              | $     
|                                                                                                                                          | Restricted Cash                                |                                              |       
|                                                                                                                                          | Accounts Receivable, net                       |                                              |       
|                                                                                                                                          |                                                | Customer                                     |       
|                                                                                                                                          |                                                | Other                                        |       
|Receivables from Affiliates                                                                                                               |                                                |                                              |      
|                                                                                                                                          | Inventories, at average cost                   |                                              |       
|                                                                                                                                          |                                                | Fossil Fuel                                  |       
|                                                                                                                                          |                                                | Materials and Supplies                       |       
|                                                                                                                                          | Other                                          |                                              |       
|                                                                                                                                          |                                                |                                              |       
|                                                                                                                                          |                                                | Total Current Assets                         |       
|                                                                                                                                          |                                                |                                              |       
|Property, Plant and Equipment, net                                                                                                        |                                                |                                              | 4,179 
|Deferred Debits and Other Assets                                                                                                          |                                                |                                              |       
|                                                                                                                                          | Regulatory Assets                              |                                              |       
|                                                                                                                                          | Investments                                    |                                              |       
|                                                                                                                                          | Pension Asset                                  |                                              |       
|                                                                                                                                          | Other                                          |                                              |       
|                                                                                                                                          |                                                |                                              |       
|                                                                                                                                          |                                                | Total Deferred Debits and Other Assets       |       
|                                                                                                                                          |                                                |                                              |       
|Total Assets                                                                                                                              |                                                | $                                            | 10,720
|                                                                                                                                          |                                                |                                              |       
|Liabilities and Shareholders' Equity                                                                                                      |                                                |                                              |       
|Current Liabilities                                                                                                                       |                                                |                                              |       
|                                                                                                                                          | Notes Payable                                  |                                              | $     
|                                                                                                                                          | Payables to Affiliates                         |                                              |       
|                                                                                                                                          | Long-Term Debt Due Within One Year             |                                              |       
|                                                                                                                                          | Accounts Payable                               |                                              |       
|                                                                                                                                          | Accrued Expenses                               |                                              |       
|                                                                                                                                          | Deferred Income Taxes                          |                                              |       
|                                                                                                                                          | Other                                          |                                              |       
|                                                                                                                                          |                                                |                                              |       
|                                                                                                                                          |                                                | Total Current Liabilities                    |       
|                                                                                                                                          |                                                |                                              |       
|Long-Term Debt                                                                                                                            |                                                |                                              | 4,951 
|Deferred Credits and Other Liabilities                                                                                                    |                                                |                                              |       
|                                                                                                                                          | Deferred Income Taxes                          |                                              |       
|                                                                                                                                          | Unamortized Investment Tax Credits             |                                              |       
|                                                                                                                                          | Non-Pension Postretirement Benefits Obligation |                                              |       
|                                                                                                                                          | Payables to Affiliates                         |                                              |       
|                                                                                                                                          | Other                                          |                                              |       
|                                                                                                                                          |                                                |                                              |       
|                                                                                                                                          |                                                | Total Deferred Credits and Other Liabilities |       
|                                                                                                                                          |                                                |                                              |       
|Commitments and Contingencies                                                                                                             |                                                |                                              |       
|Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership, which holds Solely Subordinated Debentures of the Company |                                                |                                              | 128   
|Mandatorily Redeemable Preferred Stock                                                                                                    |                                                |                                              |      
|Shareholders' Equity                                                                                                                      |                                                |                                              |       
|                                                                                                                                          | Common Stock                                   |                                              |       
|                                                                                                                                          | Receivable from Parent                         |                                              |       
|                                                                                                                                          | Preferred Stock                                |                                              |       
|                                                                                                                                          | Retained Earnings                              |                                              |       
|                                                                                                                                          | Accumulated Other Comprehensive Income         |                                              |       
|                                                                                                                                          |                                                |                                              |       
|                                                                                                                                          |                                                | Total Shareholders' Equity                   |       
|                                                                                                                                          |                                                |                                              |       
|Total Liabilities and Shareholders' Equity                                                                                                |                                                | $                                            | 10,720
|                                                                                                                                          |                                                |                                              |       

See Notes to Consolidated Financial Statements

185

---

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 |  
|------------------------------------------------------- |  | ------------ | ------ | --------------- | - | ---------------------- |  | --------------------- | ------ | ----------------- | - | -------------------------------------- | - | -------------- | ---- | -------------------------- | -
|
|Balance, December 31, 1999                              |  | $            | 3,577  |                 | $ | 137                    |  | $                     |       |                   | $ | (3                                     | ) | $              | (100 | )                          | $
|Net Income                                              |  |              |       |                 |   |                       |  |                       |       |                   |   |                                       |   |                | 507  |                            |  
|Long-Term Incentive Plan                                |  |              | 54     |                 |   |                       |  |                       |       |                   |   | (9                                     | ) |                |     |                            |  
|Deferred Compensation                                   |  |              |       |                 |   |                       |  |                       |       |                   |   | 5                                      |   |                |     |                            |  
|Common Stock Dividends                                  |  |              |       |                 |   |                       |  |                       |       |                   |   |                                       |   |                | (157 | )                          |  
|Preferred Stock Dividends                               |  |              |       |                 |   |                       |  |                       |       |                   |   |                                       |   |                | (10  | )                          |  
|Unicom Merger Consideration                             |  |              |       |                 |   |                       |  |                       |       |                   |   |                                       |   |                | (45  | )                          |  
|Common Stock Repurchases                                |  |              |       |                 |   |                       |  |                       |       |                   |   |                                       |   |                | (5   | )                          |  
|Stock Option Exercises                                  |  |              |       |                 |   |                       |  |                       |       |                   |   |                                       |   |                |     |                            |  
|Cancellation of Treasury Shares                         |  |              | (2,175 | )               |   |                       |  |                       |       |                   |   |                                       |   |                |     |                            |  
|Other Comprehensive Income, net of income taxes of $(3) |  |              |       |                 |   |                       |  |                       |       |                   |   |                                       |   |                |     |                            |  
|Reorganization Pursuant to Share Exchange               |  |              | (7     | )               |   |                       |  |                       |       |                   |   | 7                                      |   |                |     |                            |  
|                                                        |  |              |        |                 |   |                        |  |                       |        |                   |   |                                        |   |                |      |                            |  
|Balance, December 31, 2000                              |  |              | 1,449  |                 |   | 137                    |  |                       |       |                   |   |                                       |   |                | 190  |                            |  
|Net Income                                              |  |              |       |                 |   |                       |  |                       |       |                   |   |                                       |   |                | 425  |                            |  
|Common Stock Dividends                                  |  |              |       |                 |   |                       |  |                       |       |                   |   |                                       |   |                | (342 | )                          |  
|Preferred Stock Dividends                               |  |              |       |                 |   |                       |  |                       |       |                   |   |                                       |   |                | (10  | )                          |  
|Receivable from Parent                                  |  |              | 1,983  |                 |   |                       |  |                       | (1,983 | )                 |   |                                       |   |                |     |                            |  
|Repayment of Receivable from Parent                     |  |              |       |                 |   |                       |  |                       | 105    |                   |   |                                       |   |                |     |                            |  
|Stock Option Exercises                                  |  |              | (26    | )               |   |                       |  |                       |       |                   |   |                                       |   |                |     |                            |  
|Capital Contribution from Parent                        |  |              | 121    |                 |   |                       |  |                       |       |                   |   |                                       |   |                |     |                            |  
|Net Assets Transferred in Restructuring                 |  |              | (1,608 | )               |   |                       |  |                       |       |                   |   |                                       |   |                |     |                            |  
|Other Comprehensive Income, net of income taxes of $16  |  |              |       |                 |   |                       |  |                       |       |                   |   |                                       |   |                |     |                            |  
|                                                        |  |              |        |                 |   |                        |  |                       |        |                   |   |                                        |   |                |      |                            |  
|Balance, December 31, 2001                              |  |              | 1,919  |                 |   | 137                    |  |                       | (1,878 | )                 |   |                                       |   |                | 263  |                            |  
|Net Income                                              |  |              |       |                 |   |                       |  |                       |       |                   |   |                                       |   |                | 486  |                            |  
|Common Stock Dividends                                  |  |              |       |                 |   |                       |  |                       |       |                   |   |                                       |   |                | (340 | )                          |  
|Preferred Stock Dividends                               |  |              |       |                 |   |                       |  |                       |       |                   |   |                                       |   |                | (8   | )                          |  
|Repayment of Receivable from Parent                     |  |              |       |                 |   |                       |  |                       | 120    |                   |   |                                       |   |                |     |                            |  
|Capital Contribution from Parent                        |  |              | 30     |                 |   |                       |  |                       |       |                   |   |                                       |   |                |     |                            |  
|Allocation of tax benefit from Parent                   |  |              | 27     |                 |   |                       |  |                       |       |                   |   |                                       |   |                |     |                            |  
|Other Comprehensive Income, net of income taxes of $(9) |  |              |       |                 |   |                       |  |                       |       |                   |   |                                       |   |                |     |                            |  
|                                                        |  |              |        |                 |   |                        |  |                       |        |                   |   |                                        |   |                |      |                            |  
|Balance, December 31, 2002                              |  | $            | 1,976  |                 | $ | 137                    |  | $                     | (1,758 | )                 | $ |                                       |   | $              | 401  |                            | $
|                                                        |  |              |        |                 |   |                        |  |                       |        |                   |   |                                        |   |                |      |                            |  

See Notes to Consolidated Financial Statements

186

---

PECO Energy Company and Subsidiary Companies  Consolidated Statements of Comprehensive Income

|                                        |                                                                                                     | For the Years Ended December 31, |    
|--------------------------------------- | --------------------------------------------------------------------------------------------------- | -------------------------------- | ---
|
|
|Net Income                              |                                                                                                     | $                                | 486
|Other Comprehensive Income (Loss)       |                                                                                                     |                                  |    
|                                        | SFAS 133 Transition Adjustment, net of income taxes of $29                                          |                                  | $  
|                                        | Cash Flow Hedge Fair Value Adjustment, net of income taxes of $(8) and $(13), respectively          |                                  |    
|                                        | Unrealized Gain (Loss) on Marketable Securities, net of income taxes of $(1) and $(3), respectively |                                  |    
|                                        |                                                                                                     |                                  |    
|Total Other Comprehensive Income (Loss) |                                                                                                     |                                  | (14
|                                        |                                                                                                     |                                  |    
|Total Comprehensive Income              |                                                                                                     | $                                | 472
|                                        |                                                                                                     |                                  |    

See
Notes to Consolidated Financial Statements

187

---



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 
|Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income taxes |  |      | 13  |      |   | 15  
|                                                                                                                            |  |      |     |      |   |     
|Pro forma net income                                                                                                        |  | $    | 473 |      | $ | 410 
|                                                                                                                            |  |      |     |      |   |     

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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
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.

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

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 PECO's generation

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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.

197

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7. Supplemental Financial Information

Supplemental Income Statement Information

|                        |  | For the Years Ended December 31,
|----------------------- |  | --------------------------------
|
|Taxes Other Than Income |  |                                 
|Utility(a)              |  | $                               
|Real estate             |  |                                 
|Payroll                 |  |                                 
|Other                   |  |                                 
|                        |  |                                 
|Total                   |  | $                               
|                        |  |                                 

---

|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,
|----------------------------------- | ----------------------------------------------------------------- | --------------------------------
|
|Cash paid during the year:          |                                                                   |                                 
|                                    | Interest (net of amount capitalized)                              |                                 
|                                    | Income taxes (net of refunds)                                     |                                 
|Non-cash investing and financing:   |                                                                   |                                 
|                                    | Contribution of Receivable from Parent                            |                                 
|                                    | Net Assets Transferred as a Result of the Corporate Restructuring |                                 
|                                    | Investment in Sithe                                               |                                 
|                                    | Issuance of InfraSource stock                                     |                                 
|Depreciation and amortization:      |                                                                   |                                 
|                                    | Property, plant and equipment                                     |                                 
|                                    | Regulatory assets                                                 |                                 
|                                    | Nuclear Fuel                                                      |                                 
|                                    | Decommissioning                                                   |                                 
|                                    | Goodwill                                                          |                                 
|                                    |                                                                   |                                 
|Total Depreciation and Amortization |                                                                   | $                               
|                                    |                                                                   |                                 

198

---

Supplemental Balance Sheet Information

|                                                             |  | December 31,
|------------------------------------------------------------ |  | ------------
|
|Regulatory Assets                                            |  |             
|Competitive transition charge                                |  | $           
|Recoverable deferred income taxes (see Note 12Income Taxes) |  |             
|Non-pension postretirement benefits                          |  |             
|Reacquired debt costs                                        |  |             
|Compensated absences                                         |  |             
|                                                             |  |             
|Long-Term Regulatory Assets                                  |  |             
|Deferred energy costs (current asset)                        |  |             
|                                                             |  |             
|Total                                                        |  | $           
|                                                             |  |             



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,
|---------------------- |  | ------------
|
|Accrued Expenses       |  |             
|Taxes Accrued          |  | $           
|Interest Accrued       |  |             
|Other Accrued Expenses |  |             
|                       |  |             
|                       |  | $           
|                       |  |             

199

---

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 |      
|Gas                                    |                                     |      | 1,319 |      
|Common                                 |                                     |      | 404   |      
|Construction Work in Progress          |                                     |      | 138   |      
|Other Property, Plant and Equipment    |                                     |      | 19    |      
|                                       |                                     |      |       |      
|                                       | Total Property, Plant and Equipment |      |       | 6,084
|                                       | Less Accumulated Depreciation       |      |       | 1,905
|                                       |                                     |      |       |      
|Property, Plant and Equipment, net     |                                     | $    | 4,179 |      
|                                       |                                     |      |       |      

10. Notes Payable

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

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.

200

---

11. Long-Term Debt

|                                           |                                             |                |             |             |      | December 31, |      
|------------------------------------------ | ------------------------------------------- | -------------- | ----------- | ----------- | ---- | ------------ | -----
|
|
|Securitized Long-Term Debt                 |                                             |                |             |             |      |              |      
|                                           | PETT Transition Bonds Series 1999-A:        |                |             |             |      |              |      
|                                           |                                             | Fixed rates    |             | 5.63%-6.13% |      | 2003-2008    | (a)  
|                                           |                                             | Floating rates |             | 1.48%-1.55% |      | 2004-2007    | (a)  
|                                           | PETT Transition Bonds Series 2000-A:        |                | 7.63%-7.65% |             | 2009 | (a)          |      
|                                           | PETT Transition Bonds Series 2001:          |                | 6.52%       |             | 2010 | (a)          |      
|Other Long-Term Debt                       |                                             |                |             |             |      |              |      
|                                           | First and Refunding Mortgage Bonds(b)(c):   |                |             |             |      |              |      
|                                           |                                             | Fixed rates    |             | 4.75%-6.63% |      | 2003-2012    |      
|                                           |                                             | Floating rates |             | 1.08%-1.41% |      | 2012         |      
|                                           | Pollution control notes:                    |                |             |             |      |              |      
|                                           |                                             | Fixed rates    |             | 5.20%-5.30% |      | 2021-2034    |      
|                                           |                                             | Floating rates |             | 1.20%       |      | 2027         |      
|                                           | Notes payableaccounts receivable agreement |                | 1.42%       |             | 2005 |              |      
|                                           |                                             |                |             |             |      |              |      
|Total Long-Term Debt(d)                    |                                             |                |             |             |      |              | 5,644
|Unamortized debt discount and premium, net |                                             |                |             |             |      |              | (4   
|Due within one year                        |                                             |                |             |             |      |              | (689 
|                                           |                                             |                |             |             |      |              |      
|Long-Term Debt                             |                                             |                |             |             |      | $            | 4,951
|                                           |                                             |                |             |             |      |              |      

---

2003

$
6892004


3802005


5032006


5002007


641Thereafter


2,931Total

$
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

201

---

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.

202

---

12. Income Taxes

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

|                                                                    |                            | For the Year Ended December 31, |    
|------------------------------------------------------------------- | -------------------------- | ------------------------------- | ---
|
|Included in operations:                                             |                            |                                 |    
|Federal                                                             |                            |                                 |    
|                                                                    | Current                    |                                 | $  
|                                                                    | Deferred                   |                                 |    
|                                                                    | Investment tax credit, net |                                 |    
|State                                                               |                            |                                 |    
|                                                                    | Current                    |                                 |    
|                                                                    | Deferred                   |                                 |    
|                                                                    |                            |                                 |    
|                                                                    |                            | $                               | 259
|                                                                    |                            |                                 |    
|Included in cumulative effects of changes in accounting principles: |                            |                                 |    
|Federal                                                             |                            |                                 |    
|                                                                    | Deferred                   |                                 | $  
|State                                                               |                            |                                 |    
|                                                                    | Deferred                   |                                 |    
|                                                                    |                            |                                 |    
|                                                                    |                            | $                               |   
|                                                                    |                            |                                 |    

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

|                            |                                                       | For the Year Ended December 31, |     
|--------------------------- | ----------------------------------------------------- | ------------------------------- | ----
|
|U.S. Federal statutory rate |                                                       | 35.0                            | %   
|Increase (decrease) due to: |                                                       |                                 |     
|                            | Plant basis differences                               |                                 | (1.5
|                            | State income taxes, net of Federal income tax benefit |                                 | 0.7 
|                            | Amortization of investment tax credit                 |                                 | (0.3
|                            | Other, net                                            |                                 | 0.9 
|                            |                                                       |                                 |     
|Effective income tax rate   |                                                       | 34.8                            | %   
|                            |                                                       |                                 |     

203

---

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, |      
|------------------------------------------------ | --------------------------------------------------- | ------------------------------- | -----
|
|Deferred tax liabilities:                        |                                                     |                                 |      
|                                                 | Plant basis difference                              |                                 | $    
|                                                 | Deferred investment tax credits                     |                                 |      
|                                                 | Unrealized gain on derivative financial instruments |                                 |      
|                                                 | Deferred debt refinancing costs                     |                                 |      
|                                                 |                                                     |                                 |      
|Total deferred tax liabilities                   |                                                     |                                 | 3,026
|                                                 |                                                     |                                 |      
|Deferred tax assets:                             |                                                     |                                 |      
|                                                 | Deferred pension and postretirement obligations     |                                 |      
|                                                 | Other, net                                          |                                 |      
|                                                 |                                                     |                                 |      
|Total deferred tax assets                        |                                                     |                                 | (72  
|                                                 |                                                     |                                 |      
|Deferred income taxes (net) on the balance sheet |                                                     | $                               | 2,954
|                                                 |                                                     |                                 |      

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.

204

---

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,
|------------------------------------- |  | - | ------ | ------------
|
|
|
|Series (without mandatory redemption) |  |   |        |             
|$4.68                                 |  | $ | 104.00 |             
|$4.40                                 |  |   | 112.50 |             
|$4.30                                 |  |   | 102.00 |             
|$3.80                                 |  |   | 106.00 |             
|$7.48                                 |  |   | (b     | )           
|                                      |  |   |        |             
|                                      |  |   |        |             
|Series (with mandatory redemption)    |  |   |        |             
|$6.12                                 |  |   | (c     | )           
|                                      |  |   |        |             
|Total preferred stock                 |  |   |        |             
|                                      |  |   |        |             

---

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

205

---

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

|            |                   |  |      |  |      |   |   | December 31,
|----------- | ----------------- |  | ---- |  | ---- | - | - | ------------
|
|
|PECO Energy |                   |  |      |  |      |   |   |             
|            | Capital Trust II  |  | 2037 |  | 8.00 | % | $ | 25          
|PECO Energy |                   |  |      |  |      |   |   |             
|            | Capital Trust III |  | 2028 |  | 7.38 | % |   | 1,000       
|            |                   |  |      |  |      |   |   |             
|Total       |                   |  |      |  |      |   |   |             
|            |                   |  |      |  |      |   |   |             

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.

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.

206

---

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  |  
|-------------------------------------- | ------------------------------------------------------ | ---- | --- | ----- | -
|
|Non-derivatives:                       |                                                        |      |     |       |  
|Liabilities                            |                                                        |      |     |       |  
|                                       | Long-term debt (including amounts due within one year) |      | $   | 5,640 |  
|COMRPS                                 |                                                        | $    | 128 |       | $
|Mandatorily Redeemable Preferred Stock |                                                        | $    |    |       | $
|Derivatives:                           |                                                        |      |     |       |  
|                                       | Interest rate swaps                                    |      | $   | (22   | )

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.

207

---

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 |   |    
|------------------------------------ |  | - | --- | ----------------- | - | ---
|
|
|
|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 |                   |   |   
|Surety Bonds(e)                      |  |   | 67  |                   |   | 67 
|                                     |  |   |     |                   |   |    
|Total Commercial Commitments         |  | $ | 667 |                   | $ | 513
|                                     |  |   |     |                   |   |    

---

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 |              | $ |             |  
|Intersegment Revenues:         |  |                 |        |            |   |             |   |                        |       |              |   |              |  
|2000                           |  | $               | 4      |            | $ | 795         |   | $                      | 468   |              | $ |             |  
|Depreciation and Amortization: |  |                 |        |            |   |             |   |                        |       |              |   |              |  
|2000                           |  | $               | 195    |            | $ | 98          |   | $                      | 32    |              | $ |             |  
|Operating Expenses:            |  |                 |        |            |   |             |   |                        |       |              |   |              |  
|2000                           |  | $               | 2,242  |            | $ | 2,398       |   | $                      | 1,186 |              | $ | 169          |  
|Interest Expense:              |  |                 |        |            |   |             |   |                        |       |              |   |              |  
|2000                           |  | $               | 405    |            | $ | 32          |   | $                      | 3     |              | $ | 23           |  
|Income Taxes:                  |  |                 |        |            |   |             |   |                        |       |              |   |              |  
|2000                           |  | $               | (300   | )          | $ | (111        | ) | $                      | 166   |              | $ | (23          | )
|Net Income/(Loss):             |  |                 |        |            |   |             |   |                        |       |              |   |              |  
|2000(a)                        |  | $               | 430    |            | $ | 233         |   | $                      | 47    |              | $ | (213         | )
|Capital Expenditures:          |  |                 |        |            |   |             |   |                        |       |              |   |              |  
|2000                           |  | $               | 219    |            | $ | 243         |   | $                      | 64    |              | $ | 23           |  
|Total Assets:                  |  |                 |        |            |   |             |   |                        |       |              |   |              |  
|2000                           |  | $               | 13,100 |            | $ | 1,648       |   | $                      | 991   |              | $ | (963         | )

---

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,
|------------------------------------------------ | -------------- | ---------------------------
|
|Operating Revenues from Affiliate                |                |                            
|                                                 | Generation(1)  |                            
|Purchased Power from Affiliate                   |                |                            
|                                                 | Generation(2)  |                            
|Purchased Power from Unconsolidated Affiliate(3) |                |                            
|O&M from Affiliates                              |                |                            
|                                                 | BSC(4)         |                            
|                                                 | Enterprises(5) |                            
|Capitalized Costs                                |                |                            
|                                                 | Enterprises(5) |                            
|                                                 | BSC(4)         |                            
|Interest Expense from Affiliates                 |                |                            
|                                                 | ComEd(6)       |                            
|Interest Income from Affiliates                  |                |                            
|                                                 | Generation(7)  |                            
|                                                 | Other          |                            
|Cash Dividends Paid to Parent                    |                |                            

|                                               |                | December 31,
|---------------------------------------------- | -------------- | ------------
|
|Receivables from Affiliates                    |                |             
|                                               | Other          |             
|Payables to Affiliates                         |                |             
|                                               | Generation(2)  |             
|                                               | BSC(4)         |             
|                                               | Enterprises(5) |             
|                                               | Other          |             
|Deferred Credits and Other Liabilities         |                |             
|                                               | BSC            |             
|Shareholders' EquityReceivable from Parent(8) |                |             

---

211

---

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 |   |     |  |  
|------------ |  | - | ----- |  | - | ----- |  | - | --- | -------------------------------------------------------------------------- | - | --- |  | -
|
|
|
|
|March 31     |  | $ | 1,020 |  | $ | 1,051 |  | $ | 227 |                                                                            | $ | 287 |  | $
|June 30      |  | $ | 995   |  | $ | 906   |  | $ | 234 |                                                                            | $ | 246 |  | $
|September 30 |  | $ | 1,224 |  | $ | 1,051 |  | $ | 323 |                                                                            | $ | 258 |  | $
|December 31  |  | $ | 1,094 |  | $ | 957   |  | $ | 309 |                                                                            | $ | 208 |  | $

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,   |    
|------------------------------------------------------------------------------------------------------ | ---------------------------------------------------- | --------------------------------- | ---
|
|
|OPERATING REVENUES                                                                                     |                                                      |                                   |    
|                                                                                                       | Operating Revenues                                   |                                   | $  
|                                                                                                       | Operating Revenues from Affiliates                   |                                   |    
|                                                                                                       |                                                      |                                   |    
|                                                                                                       |                                                      | Total Operating Revenues          |    
|                                                                                                       |                                                      |                                   |    
|OPERATING EXPENSES                                                                                     |                                                      |                                   |    
|                                                                                                       | Purchased Power                                      |                                   |    
|                                                                                                       | Purchased Power from Affiliates                      |                                   |    
|                                                                                                       | Fuel                                                 |                                   |    
|                                                                                                       | Operating and Maintenance                            |                                   |    
|                                                                                                       | Operating and Maintenance from Affiliates            |                                   |    
|                                                                                                       | Depreciation and Amortization                        |                                   |    
|                                                                                                       | Taxes Other Than Income                              |                                   |    
|                                                                                                       |                                                      |                                   |    
|                                                                                                       |                                                      | Total Operating Expense           |    
|                                                                                                       |                                                      |                                   |    
|OPERATING INCOME                                                                                       |                                                      |                                   | 509
|                                                                                                       |                                                      |                                   |    
|OTHER INCOME AND DEDUCTIONS                                                                            |                                                      |                                   |    
|                                                                                                       | Interest Expense                                     |                                   |    
|                                                                                                       | Interest Expense from Affiliates                     |                                   |    
|                                                                                                       | Equity in Earnings of Unconsolidated Affiliates, net |                                   |    
|                                                                                                       | Interest Income from Affiliates                      |                                   |    
|                                                                                                       | Other, Net                                           |                                   |    
|                                                                                                       |                                                      |                                   |    
|                                                                                                       |                                                      | Total Other Income and Deductions |    
|                                                                                                       |                                                      |                                   |    
|INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES                   |                                                      |                                   | 604
|INCOME TAXES                                                                                           |                                                      |                                   | 217
|                                                                                                       |                                                      |                                   |    
|INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES                                    |                                                      |                                   | 387
|CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (net of income taxes of $9 and $7, respectively) |                                                      |                                   | 13 
|                                                                                                       |                                                      |                                   |    
|NET INCOME                                                                                             |                                                      | $                                 | 400
|                                                                                                       |                                                      |                                   |    

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,                                |                                                                 
|--------------------------------------------------------- | --------------------------------- | -------------------------------------------------------------- | ----------------------------------------------------------------
|
|
|CASH FLOWS FROM OPERATING ACTIVITIES                      |                                   |                                                                |                                                                 
|Net Income                                                |                                   | $                                                              | 400                                                             
|Adjustments to Reconcile Net Income to Net Cash Flows     |                                   |                                                                |                                                                 
|                                                          | Provided by Operating Activities: |                                                                |                                                                 
|                                                          |                                   | Depreciation and Amortization, including nuclear fuel          |                                                                 
|                                                          |                                   | Cumulative Effect of a Change in Accounting                    |                                                                 
|                                                          |                                   |                                                                | Principle (net of income taxes)                                 
|                                                          |                                   | Provision for Uncollectible Accounts                           |                                                                 
|                                                          |                                   | Deferred Income Taxes                                          |                                                                 
|                                                          |                                   | Equity in (Earnings) Losses of Unconsolidated Affiliates       |                                                                 
|                                                          |                                   | Net Realized Losses on Nuclear Decommissioning Trust Funds     |                                                                 
|                                                          |                                   | Other Operating Activities                                     |                                                                 
|                                                          |                                   | Changes in Working Capital:                                    |                                                                 
|                                                          |                                   |                                                                | Accounts Receivable                                             
|                                                          |                                   |                                                                | Changes in Receivables and Payables to Affiliates, net          
|                                                          |                                   |                                                                | Inventories                                                     
|                                                          |                                   |                                                                | Accounts Payable, Accrued Expenses and Other Current Liabilities
|                                                          |                                   |                                                                | Other Current Assets                                            
|                                                          |                                   |                                                                |                                                                 
|Net Cash Flows provided by Operating Activities           |                                   |                                                                | 1,138                                                           
|                                                          |                                   |                                                                |                                                                 
|CASH FLOWS FROM INVESTING ACTIVITIES                      |                                   |                                                                |                                                                 
|                                                          |                                   | Capital Expenditures                                           |                                                                 
|                                                          |                                   | Investment in Sithe Energies, Inc.                             |                                                                 
|Acquisition of Generating Plants                          |                                   |                                                                | (445                                                            
|                                                          |                                   | Proceeds from Nuclear Decommissioning Trust Funds              |                                                                 
|                                                          |                                   | Investment in Nuclear Decommissioning Trust Funds              |                                                                 
|                                                          |                                   | Note Receivable from Affiliate                                 |                                                                 
|                                                          |                                   | Other Investing Activities                                     |                                                                 
|                                                          |                                   |                                                                |                                                                 
|Net Cash Flows used in Investing Activities               |                                   |                                                                | (1,674                                                          
|                                                          |                                   |                                                                |                                                                 
|CASH FLOWS FROM FINANCING ACTIVITIES                      |                                   |                                                                |                                                                 
|                                                          |                                   | Change in Note Payable, Affiliate                              |                                                                 
|                                                          |                                   | Contribution from Minority Interest in Consolidated Subsidiary |                                                                 
|                                                          |                                   | Issuance of Long-Term Debt                                     |                                                                 
|                                                          |                                   | Retirement of Long-Term Debt                                   |                                                                 
|                                                          |                                   | Distribution Paid to Member                                    |                                                                 
|                                                          |                                   |                                                                |                                                                 
|Net Cash Flows provided by (used in) Financing Activities |                                   |                                                                | 370                                                             
|                                                          |                                   |                                                                |                                                                 
|INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS          |                                   |                                                                | (166                                                            
|CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD          |                                   |                                                                | 224                                                             
|                                                          |                                   |                                                                |                                                                 
|CASH AND CASH EQUIVALENTS AT END OF PERIOD                |                                   | $                                                              | 58                                                              
|                                                          |                                   |                                                                |                                                                 

See
Notes to Consolidated Financial Statements

215

---



Exelon Generation Company, LLC and Subsidiary Companies  Consolidated Balance Sheets

|                                             |                                                      | December 31,                                 |       
|-------------------------------------------- | ---------------------------------------------------- | -------------------------------------------- | ------
|
|
|ASSETS                                       |                                                      |                                              |       
|CURRENT ASSETS                               |                                                      |                                              |       
|                                             | Cash and Cash Equivalents                            |                                              | $     
|                                             | Accounts Receivable, net                             |                                              |       
|                                             |                                                      | Customer                                     |       
|                                             |                                                      | Other                                        |       
|                                             | Receivables from Affiliates                          |                                              |       
|                                             | Inventories, at average cost                         |                                              |       
|                                             |                                                      | Fossil Fuel                                  |       
|                                             |                                                      | Materials and Supplies                       |       
|                                             | Deferred Income Taxes                                |                                              |       
|                                             | Other                                                |                                              |       
|                                             |                                                      |                                              |       
|                                             |                                                      | Total Current Assets                         |       
|                                             |                                                      |                                              |       
|PROPERTY, PLANT AND EQUIPMENT, NET           |                                                      |                                              | 4,800 
|DEFERRED DEBITS AND OTHER ASSETS             |                                                      |                                              |       
|                                             | Nuclear Decommissioning Trust Funds                  |                                              |       
|                                             | Investments                                          |                                              |       
|                                             | Receivable from Affiliate                            |                                              |       
|                                             | Deferred Income Taxes                                |                                              |       
|                                             | Other                                                |                                              |       
|                                             |                                                      |                                              |       
|                                             |                                                      | Total Deferred Debits and Other Assets       |       
|                                             |                                                      |                                              |       
|TOTAL ASSETS                                 |                                                      | $                                            | 11,007
|                                             |                                                      |                                              |       
|LIABILITIES AND MEMBER'S EQUITY              |                                                      |                                              |       
|CURRENT LIABILITIES                          |                                                      |                                              |       
|                                             | Long-Term Debt Due within One Year                   |                                              | $     
|                                             | Accounts Payable                                     |                                              |       
|                                             | Payables to Affiliates                               |                                              |       
|                                             | Notes Payable to Affiliates                          |                                              |       
|                                             | Accrued Expenses                                     |                                              |       
|                                             | Other                                                |                                              |       
|                                             |                                                      |                                              |       
|                                             |                                                      | Total Current Liabilities                    |       
|                                             |                                                      |                                              |       
|LONG-TERM DEBT                               |                                                      |                                              | 2,132 
|DEFERRED CREDITS AND OTHER LIABILITIES       |                                                      |                                              |       
|                                             | Unamortized Investment Tax Credits                   |                                              |       
|                                             | Nuclear Decommissioning Liability for Retired Plants |                                              |       
|                                             | Pension Obligation                                   |                                              |       
|                                             | Non-Pension Postretirement Benefits Obligation       |                                              |       
|                                             | Spent Nuclear Fuel Obligation                        |                                              |       
|                                             | Other                                                |                                              |       
|                                             |                                                      |                                              |       
|                                             |                                                      | Total Deferred Credits and Other Liabilities |       
|                                             |                                                      |                                              |       
|COMMITMENTS AND CONTINGENCIES                |                                                      |                                              |       
|MINORITY INTEREST OF CONSOLIDATED SUBSIDIARY |                                                      |                                              | 54    
|MEMBER'S EQUITY                              |                                                      |                                              |       
|                                             | Membership Interest                                  |                                              |       
|                                             | Undistributed Earnings                               |                                              |       
|                                             | Accumulated Other Comprehensive Income (Loss)        |                                              |       
|                                             |                                                      |                                              |       
|                                             |                                                      | Total Member's Equity                        |       
|                                             |                                                      |                                              |       
|TOTAL LIABILITIES AND MEMBER'S EQUITY        |                                                      | $                                            | 11,007
|                                             |                                                      |                                              |       

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 |  
|--------------------------------------------------------- | ------------------------------------------------------ | ----------------- | ------ | ------------------- | - | ---------------------- | - | -------------------------------------- | --- | --------------------- | -
|
|Balance, December 31, 1999                                |                                                        | $                 | 950    |                     | $ |                       |   | $                                      |    |                       | $
|Net Income                                                |                                                        |                   | 260    |                     |   |                       |   |                                        |    |                       |  
|Unicom Merger Consideration                               |                                                        |                   | 1,400  |                     |   |                       |   |                                        |    |                       |  
|                                                          |                                                        |                   |        |                     |   |                        |   |                                        |     |                       |  
|Balance, December 31, 2000                                |                                                        |                   | 2,610  |                     |   |                       |   |                                        |    |                       |  
|Formation of LLC                                          |                                                        |                   | (2,610 | )                   |   | 2,610                  |   |                                        |    |                       |  
|Net Income                                                |                                                        |                   |       |                     |   |                       |   |                                        | 524 |                       |  
|Non-Cash distribution to member                           |                                                        |                   |       |                     |   | (174                   | ) |                                        |    |                       |  
|Distribution to member                                    |                                                        |                   |       |                     |   | (121                   | ) |                                        |    |                       |  
|Reclassified net unrealized losses                        |                                                        |                   |        |                     |   |                        |   |                                        |     |                       |  
|                                                          | On marketable securities, net of income taxes of $(22) |                   |        |                    |   |                        |  |                                        |     |                      |  
|Other Comprehensive Income, net of income taxes of $(16)  |                                                        |                   |       |                     |   |                       |   |                                        |    |                       |  
|                                                          |                                                        |                   |        |                     |   |                        |   |                                        |     |                       |  
|Balance, December 31, 2001                                |                                                        |                   |       |                     |   | 2,315                  |   |                                        | 524 |                       |  
|Net Income                                                |                                                        |                   |       |                     |   |                       |   |                                        | 400 |                       |  
|Distribution to member                                    |                                                        |                   |       |                     |   | (30                    | ) |                                        |    |                       |  
|Allocation of tax benefit from Member                     |                                                        |                   |       |                     |   | 11                     |   |                                        |    |                       |  
|Other Comprehensive Income, net of income taxes of $(223) |                                                        |                   |       |                     |   |                       |   |                                        |    |                       |  
|                                                          |                                                        |                   |        |                     |   |                        |   |                                        |     |                       |  
|Balance, December 31, 2002                                |                                                        | $                 |       |                     | $ | 2,296                  |   | $                                      | 924 |                       | $
|                                                          |                                                        |                   |        |                     |   |                        |   |                                        |     |                       |  

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,
|-------------------------------- | ------------------------------------------------------------------------------------------------------ | --------------------------------
|
|
|Net Income                       |                                                                                                        | $                               
|Other Comprehensive Income       |                                                                                                        |                                 
|                                 | SFAS 133 Transition Adjustment, net of income taxes of $3                                              |                                 
|                                 | Cash Flow Hedge Fair Value Adjustment, net of income taxes of $(108) and $29, respectively             |                                 
|                                 | Unrealized Gain (Loss) on Marketable Securities, net of income taxes of $(110) and $(31), respectively |                                 
|                                 | Realized loss on forward starting interest rate swap net of income taxes of $(1)                       |                                 
|                                 | Interest in Other Comprehensive Income of Unconsolidated Affiliates                                    |                                 
|                                 | Net of income taxes of $(5) and $(16), respectively                                                    |                                 
|                                 |                                                                                                        |                                 
|Total Other Comprehensive Income |                                                                                                        |                                 
|                                 |                                                                                                        |                                 
|Total Comprehensive Income       |                                                                                                        | $                               
|                                 |                                                                                                        |                                 

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.

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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 
|Deduct: Total stock-based compensation expense determined under fair value based method for all awards, net of income taxes |  |      | 15  |      |   | 9   
|                                                                                                                            |  |      |     |      |   |     
|Pro forma net income                                                                                                        |  | $    | 385 |      | $ | 515 
|                                                                                                                            |  |      |     |      |   |     

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:



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.

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.

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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 |   |     |  
|------------------------------------------------------- |  | - | --- | ----------- | - | --- | -
|
|
|Employee severance payments                             |  | $ | 45  |             | $ | (12 | )
|Other benefits                                          |  |   | 5   |             |   | 2   |  
|                                                        |  |   |     |             |   |     |  
|Employee severance payments and other benefits          |  |   | 50  |             |   | (10 | )
|Actuarially determined pension and postretirement costs |  |   | 71  |             |   | (25 | )
|                                                        |  |   |     |             |   |     |  
|Unicom employee costgeneration                         |  | $ | 121 |             | $ | (35 | )
|                                                        |  |   |     |             |   |     |  

---

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   |  
|                                                                         |  |   |    

---

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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   |  
|                             |  |       |  

---

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      |   |      
|                                              |                               |  
|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 |   |      
|                                              |                               |  
|                                              | Net assets transferred        |   | $    
|                                              |                               |  

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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.

229

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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

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.

230

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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,
|----------------------------------------------- |  | -------------------------------
|
|Taxes Other Than Income                         |  |                                
|Real estate                                     |  | $                              
|Payroll                                         |  |                                
|Other                                           |  |                                
|                                                |  |                                
|Total                                           |  | $                              
|                                                |  |                                
|Equity in Earnings of Unconsolidated Affiliates |  |                                
|AmerGen                                         |  | $                              
|Sithe                                           |  |                                
|                                                |  |                                
|Total                                           |  | $                              
|                                                |  |                                
|Other, Net                                      |  |                                
|Investment income                               |  | $                              
|Other income (expense)                          |  |                                
|                                                |  |                                
|Total                                           |  | $                              
|                                                |  |                                

Supplemental Cash Flow Information

|                                             |                                                                        | For the Year Ended
December 31,
|-------------------------------------------- | ---------------------------------------------------------------------- | -------------------------------
|
|Cash paid (received) during the year:        |                                                                        |                                
|                                             | Interest (net of amount capitalized)                                   |                                
|                                             | Income taxes (net of refunds)                                          |                                
|Non-cash investing and financing activities: |                                                                        |                                
|                                             | Capital Lease Obligations                                              |                                
|                                             | Contribution of Land from Minority Interest of Consolidated Subsidiary |                                
|                                             | Note Issued to Sithe in the Sithe New England Acquisition              |                                
|Depreciation and amortization:               |                                                                        |                                
|                                             | Property, plant and equipment                                          |                                
|                                             | Nuclear fuel                                                           |                                
|                                             | Decommissioning                                                        |                                
|                                             |                                                                        |                                
|Total Depreciation and Amortization          |                                                                        | $                              
|                                             |                                                                        |                                

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Supplemental Balance Sheet Information

|                      |  | December 31,
|--------------------- |  | ------------
|
|Investments           |  |             
|Investment in Sithe   |  | $           
|Investment in AmerGen |  |             
|Other                 |  |             
|                      |  |             
|Total                 |  | $           
|                      |  |             

|                 |  | December 31,
|---------------- |  | ------------
|
|Accrued Expenses |  |             
|Taxes Accrued    |  | $           
|Other            |  |             
|                 |  |             
|Total            |  | $           
|                 |  |             

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  |      
|Nuclear Fuel                        |                                                                                                                                                        |      | 3,112  |      
|Construction Work in Progress       |                                                                                                                                                        |      | 2,179  |      
|Other Property, Plant and Equipment |                                                                                                                                                        |      | 52     |      
|                                    |                                                                                                                                                        |      |        |      
|Total Property, Plant and Equipment |                                                                                                                                                        |      | 11,021 |      
|                                    | 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
|                                    |                                                                                                                                                        |      |        |      
|Property, Plant and Equipment, net  |                                                                                                                                                        | $    | 4,800  |      
|                                    |                                                                                                                                                        |      |        |      

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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 |           
|---------------------- | ----------------------------- | ---------------- | ----------
|
|
|Operator               |                               |                  | Generation
|Participating Interest |                               |                  | 50        
|Generation's Share:    |                               |                  |           
|Plant                  |                               | $                | 417       
|                       | Accumulated Depreciation      |                  | $         
|                       | Construction Work in Progress |                  | $         

|                       |                               | Production Plant |           
|---------------------- | ----------------------------- | ---------------- | ----------
|
|
|Operator               |                               |                  | Generation
|Participating Interest |                               |                  | 50        
|Generation's Share:    |                               |                  |           
|Plant                  |                               | $                | 387       
|                       | Accumulated Depreciation      |                  | $         
|                       | Construction Work in Progress |                  | $         

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.

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

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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.

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 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

235

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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.

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 corporate restructuring.

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10. Long-Term Debt

Long-term debt is comprised of the following:

|                                        |                                            | December 31, 2002 |     |           |  |   |      
|--------------------------------------- | ------------------------------------------ | ----------------- | --- | --------- |  | - | -----
|
|
|
|SBG Facility                            |                                            | 6.37%             | (a) | 2007      |  | $ | 1,036
|Senior unsecured notes                  |                                            | 6.95%             |     | 2011      |  |   | 700  
|Pollution control notes, floating rates |                                            | 1.23%-1.50%       |     | 2016-2034 |  |   | 346  
|Notes payable and other                 |                                            | 7.25%-7.83%       |     | 2004-2020 |  |   | 56   
|                                        |                                            |                   |     |           |  |   |      
|Total Long-Term Debt(b)                 |                                            |                   |     |           |  |   | 2,138
|                                        | Unamortized debt discount and premium, net |                   |     |           |  |   |      
|                                        | Due within one year                        |                   |     |           |  |   |      
|                                        |                                            |                   |     |           |  |   |      
|Long-Term Debt                          |                                            |                   |     |           |  | $ | 2,132
|                                        |                                            |                   |     |           |  |   |      

---

2003

$
52004


12005


2006


2007


1,036Thereafter


1,096Total

$
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.

237

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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, |    
|------------------------------------------------------------------- | --------------------- | ------------------------------- | ---
|
|Included in operations:                                             |                       |                                 |    
|Federal                                                             |                       |                                 |    
|                                                                    | Current               |                                 | $  
|                                                                    | Deferred              |                                 |    
|                                                                    | Investment tax credit |                                 |    
|State                                                               |                       |                                 |    
|                                                                    | Current               |                                 |    
|                                                                    | Deferred              |                                 |    
|                                                                    |                       |                                 |    
|                                                                    |                       | $                               | 217
|                                                                    |                       |                                 |    
|Included in cumulative effects of changes in accounting principles: |                       |                                 |    
|Federal                                                             |                       |                                 |    
|                                                                    | Deferred              |                                 | $  
|State                                                               |                       |                                 |    
|                                                                    | Deferred              |                                 |    
|                                                                    |                       |                                 |    
|                                                                    |                       | $                               | 9  
|                                                                    |                       |                                 |    

The
effective income tax rate differed from the Federal statutory rate principally due to the following:

|                            |                                                       | For the Year Ended December 31, |     
|--------------------------- | ----------------------------------------------------- | ------------------------------- | ----
|
|U.S. Federal statutory rate |                                                       | 35.0                            | %   
|Increase (decrease) due to: |                                                       |                                 |     
|                            | State income taxes, net of Federal income tax benefit |                                 | 3.7 
|                            | Tax-exempt interest                                   |                                 | (2.3
|                            | Nuclear decommissioning trust income                  |                                 | 0.9 
|                            | Amortization of investment tax credit                 |                                 | (0.9
|                            | Other                                                 |                                 | (0.5
|                            |                                                       |                                 |     
|Effective income tax rate   |                                                       | 35.9                            | %   
|                            |                                                       |                                 |     

238

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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, |     
|------------------------------------------------ | ---------------------------------------------------- | ------------ | ----
|
|Deferred tax assets:                             |                                                      |              |     
|                                                 | Decommissioning and decontamination obligations      |              | $   
|                                                 | Deferred pension and postretirement obligations      |              |     
|                                                 | Unrealized gains on derivative financial instruments |              |     
|                                                 | Other, net                                           |              |     
|                                                 |                                                      |              |     
|Total deferred tax assets                        |                                                      |              | 982 
|                                                 |                                                      |              |     
|Deferred tax liabilities:                        |                                                      |              |     
|                                                 | Plant basis difference                               |              |     
|                                                 | Deferred investment tax credit, net                  |              |     
|                                                 | Unrealized gains on derivative financial instruments |              |     
|                                                 | Decommissioning and decontamination obligations      |              |     
|                                                 | Emission allowances                                  |              |     
|                                                 | Severance obligations                                |              |     
|                                                 |                                                      |              |     
|Total deferred tax liabilities                   |                                                      |              | (930
|                                                 |                                                      |              |     
|Deferred income taxes (net) on the balance sheet |                                                      | $            | 52  
|                                                 |                                                      |              |     

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

239

---

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
|--------------------------------------- |  | - | --- | -----------------
|
|Credit Facility(a)                      |  | $ |    |                  
|Letters of Credit (non-debt)(b)         |  |   | 11  |                  
|Letters of Credit (Long-Term Debt)(c)   |  |   | 346 |                  
|Performance Guarantees(d)               |  |   | 101 |                  
|Surety Bonds(e)                         |  |   | 43  |                  
|Energy Marketing Contract Guarantees(f) |  |   | 1   |                  
|Nuclear Insurance Guarantee(g)          |  |   | 134 |                  
|Sithe New England Equity Guarantee(h)   |  |   | 38  |                  
|                                        |  |   |     |                  
|Total Commercial Commitments            |  | $ | 674 |                  
|                                        |  |   |     |                  

---

240

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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) |  | $            
|Nuclear fuel        |  |              
|                    |  |              
|Total               |  | $            
|                    |  |              

---

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
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.

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.

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.

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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 |  |  
|---------- |  | - | ----- |  | - | ------------------------- |  | -
|
|
|2003       |  | $ | 589   |  | $ | 2,442                     |  | $
|2004       |  |   | 639   |  |   | 1,088                     |  |  
|2005       |  |   | 356   |  |   | 272                       |  |  
|2006       |  |   | 328   |  |   | 92                        |  |  
|2007       |  |   | 408   |  |   | 22                        |  |  
|Thereafter |  |   | 3,742 |  |   | 1                         |  |  
|           |  |   |       |  |   |                           |  |  
|Total      |  | $ | 6,062 |  | $ | 3,917                     |  | $
|           |  |   |       |  |   |                           |  |  

---

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 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.

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.

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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 
|---------------- | ------------------------------------------------------ | ---- | - | -----
|
|Non-derivatives: |                                                        |      |   |      
|Assets:          |                                                        |      |   |      
|                 | Nuclear decommissioning trust funds                    |      | $ | 3,053
|Liabilities:     |                                                        |      |   |      
|                 | Long-term debt (including amounts due within one year) |      | $ | 2,137
|Derivatives:     |                                                        |      |   |      
|                 | Energy derivatives                                     |      | $ | (163 

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
|----------------------------------- | ---------------------- | - | ----- | -----------------
|
|Equity securities                   |                        | $ | 1,763 |                  
|Debt securities                     |                        |   |       |                  
|                                    | Government obligations |   |       | 938              
|                                    | Other debt securities  |   |       | 698              
|                                    |                        |   |       |                  
|Total debt securities               |                        |   | 1,636 |                  
|                                    |                        |   |       |                  
|Total available-for-sale securities |                        | $ | 3,399 |                  
|                                    |                        |   |       |                  

|                                    |                        |   |       | December 31, 2001
|----------------------------------- | ---------------------- | - | ----- | -----------------
|
|Equity securities                   |                        | $ | 1,666 |                  
|Debt securities                     |                        |   |       |                  
|                                    | Government obligations |   |       | 882              
|                                    | Other debt securities  |   |       | 701              
|                                    |                        |   |       |                  
|Total debt securities               |                        |   | 1,583 |                  
|                                    |                        |   |       |                  
|Total available-for-sale securities |                        | $ | 3,249 |                  
|                                    |                        |   |       |                  

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 |      | $
|Gross realized gains  |  |      | 56    |      |  
|Gross realized losses |  |      | (86   | )    |  

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
|-------------- |  | ------------------ | ----- | ---------------- | - | -------------------------------------------------------------------------- |  | ----------
|
|Quarter ended: |  |                    |       |                  |   |                                                                            |  |           
|March 31       |  | $                  | 1,461 |                  | $ | 1,628                                                                      |  | $         
|June 30        |  |                    | 1,559 |                  |   | 1,583                                                                      |  |           
|September 30   |  |                    | 2,212 |                  |   | 2,193                                                                      |  |           
|December 31    |  |                    | 1,626 |                  |   | 1,422                                                                      |  |           

16. Related-Party Transactions

Generation's financial statements include related-party transactions as reflected in the tables below.

|                                   |                  | For the Years Ended December 31,
|---------------------------------- | ---------------- | --------------------------------
|
|Operating Revenues from Affiliates |                  |                                 
|                                   | ComEd(1)         |                                 
|                                   | PECO(1)          |                                 
|                                   | Exelon Energy(2) |                                 
|Purchased Power from Affiliates    |                  |                                 
|                                   | AmerGen(3)       |                                 
|                                   | ComEd(4)         |                                 
|                                   | PECO(4)          |                                 
|                                   | Exelon Energy(4) |                                 
|O&M from Affiliates                |                  |                                 
|                                   | Sithe(5)         |                                 
|                                   | ComEd(4)         |                                 
|                                   | PECO(4)          |                                 
|                                   | BSC(17)          |                                 
|Interest Expense from Affiliates   |                  |                                 
|                                   | Sithe(11)        |                                 
|                                   | Exelon(6,7)      |                                 
|                                   | ComEd(9)         |                                 
|                                   | PECO(8)          |                                 
|Interest Income from Affiliates    |                  |                                 
|                                   | AmerGen(10)      |                                 
|                                   | Sithe(18)        |                                 
|                                   | ComEd(12,13)     |                                 
|Services Provided to Affiliates    |                  |                                 
|                                   | AmerGen(14)      |                                 
|                                   | Sithe(15)        |                                 

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|                                    |                                           | December 31,
|----------------------------------- | ----------------------------------------- | ------------
|
|Receivables from Affiliates         |                                           |             
|                                    | ComEd(1,4,9)                              |             
|                                    | ComEd Decommissioning(16)                 |             
|                                    | AmerGen(3,10)                             |             
|                                    | PECO(1)                                   |             
|                                    | BSC(17)                                   |             
|                                    | Exelon Energy(2)                          |             
|Long-Term Receivable from Affiliate |                                           |             
|                                    | Generation decommissioning obligation(16) |             
|                                    | Other                                     |             
|Payables to Affiliates              |                                           |             
|                                    | Sithe(5)                                  |             
|                                    | Exelon(7)                                 |             
|                                    | BSC(17)                                   |             
|Notes Payable to Affiliates         |                                           |             
|                                    | Exelon(6)                                 |             
|                                    | Sithe(11)                                 |             

---

251

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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 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 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.

253

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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, |    
|----------------------------------------------------------------- |  | -------------------------------- | ---
|
|Income Statement Information                                      |  |                                  |    
|Operating revenues                                                |  | $                                | 644
|Operating income                                                  |  |                                  | 124
|Income before cumulative effect of change in accounting principle |  |                                  | 117
|Net Income                                                        |  |                                  | 161

|                                              |  | December 31, |      
|--------------------------------------------- |  | ------------ | -----
|
|Balance Sheet Information                     |  |              |      
|Current assets                                |  | $            | 89   
|Noncurrent assets                             |  |              | 1,490
|                                              |  |              |      
|Total assets                                  |  | $            | 1,579
|                                              |  |              |      
|Current liabilities                           |  | $            | 148  
|Noncurrent liabilities                        |  |              | 1,112
|Members' capital                              |  |              | 80   
|Additional paid-in capital                    |  |              |     
|Retained earnings                             |  |              | 316  
|Accumulated other comprehensive income (loss) |  |              | (77  
|                                              |  |              |      
|Total capitalization and liabilities          |  | $            | 1,579
|                                              |  |              |      

254

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The
table below presents summarized financial information for Sithe:

|                             |  | For the Years Ended December 31,
|---------------------------- |  | --------------------------------
|
|Income Statement Information |  |                                 
|Operating revenues           |  | $                               
|Operating income             |  |                                 
|Net Income                   |  |                                 

|                                              |  | December 31, |      
|--------------------------------------------- |  | ------------ | -----
|
|Balance Sheet Information                     |  |              |      
|Current assets                                |  | $            | 1,145
|Noncurrent assets                             |  |              | 1,427
|                                              |  |              |      
|Total assets                                  |  | $            | 2,572
|                                              |  |              |      
|Current liabilities                           |  | $            | 256  
|Noncurrent liabilities                        |  |              | 1,509
|Additional paid-in capital                    |  |              | 735  
|Retained earnings                             |  |              | 89   
|Accumulated other comprehensive income (loss) |  |              | (17  
|                                              |  |              |      
|Total capitalization and liabilities          |  | $            | 2,572
|                                              |  |              |      

255

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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

257

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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 |                                                                                                
|Equity Compensation plans not approved by security holders |  | 1,104,681                                                              |  |                                               | 41.09 |                                                                                                
|                                                           |  |                                                                        |  |                                               |       |                                                                                                
|Total                                                      |  | 15,886,990                                                             |  | $                                             | 45.80 |                                                                                                
|                                                           |  |                                                                        |  |                                               |       |                                                                                                

---

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

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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

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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

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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

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| |  | 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                                                  



263

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EXELON CORPORATION AND SUBSIDIARY COMPANIES        Schedule IIValuation and Qualifying Accounts  (in millions)

|Column A                                    |  | Column B |     | Column C |   | Column D |  | Column E
|------------------------------------------- |  | -------- | --- | -------- | - | -------- |  | --------
|
|
|For The Year Ended December 31, 2002        |  |          |     |          |   |          |  |         
|Allowance for Uncollectible Accounts        |  | $        | 213 |          | $ | 129      |  | $       
|Reserve for:                                |  |          |     |          |   |          |  |         
|Merger-Related Costs                        |  | $        | 114 |          | $ |         |  | $       
|Injuries and Damages                        |  | $        | 72  |          | $ | 42       |  | $       
|Environmental Investigation and Remediation |  | $        | 156 |          | $ | 21       |  | $       
|Obsolete Materials                          |  | $        | 18  |          | $ | 9        |  | $       
|For The Year Ended December 31, 2001        |  |          |     |          |   |          |  |         
|Allowance for Uncollectible Accounts        |  | $        | 200 |          | $ | 145      |  | $       
|Reserve for:                                |  |          |     |          |   |          |  |         
|Merger-Related Costs                        |  | $        | 144 |          | $ |         |  | $       
|Injuries and Damages                        |  | $        | 69  |          | $ | 17       |  | $       
|Environmental Investigation and Remediation |  | $        | 171 |          | $ | 1        |  | $       
|Obsolete Materials                          |  | $        | 103 |          | $ | 16       |  | $       
|For The Year Ended December 31, 2000        |  |          |     |          |   |          |  |         
|Allowance for Uncollectible Accounts        |  | $        | 112 |          | $ | 87       |  | $       
|Reserve for:                                |  |          |     |          |   |          |  |         
|Merger-Related Costs                        |  | $        |    |          | $ |         |  | $       
|Injuries and Damages                        |  | $        | 23  |          | $ | 9        |  | $       
|Environmental Investigation and Remediation |  | $        | 57  |          | $ | 26       |  | $       
|Obsolete Materials                          |  | $        |    |          | $ | 48       |  | $       

---

264

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| |  | 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                                                                                                                                                     



265

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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
|------------------------------------------- |  | -------- | --- | -------- | - | -------- |  | -------- | --- | --------
|
|
|For The Year Ended December 31, 2002        |  |          |     |          |   |          |  |          |     |         
|Allowance for Uncollectible Accounts        |  | $        | 49  |          | $ | 50       |  | $        |    |         
|Reserve for:
Merger-Related Costs           |  | $        | 63  |          | $ |         |  | $        | (9  | )       
|Injuries and Damages                        |  | $        | 37  |          | $ | 23       |  | $        |    |         
|Environmental Investigation and Remediation |  | $        | 105 |          | $ | 19       |  | $        |    |         
|Obsolete Materials                          |  | $        | 6   |          | $ |         |  | $        |    |         
|For The Year Ended December 31, 2001        |  |          |     |          |   |          |  |          |     |         
|Allowance for Uncollectible Accounts        |  | $        | 60  |          | $ | 42       |  | $        | 1   |         
|Reserve for:
Merger-Related Costs           |  | $        | 144 |          | $ |         |  | $        | 25  |         
|Injuries and Damages                        |  | $        | 48  |          | $ | 4        |  | $        |    |         
|Environmental Investigation and Remediation |  | $        | 117 |          | $ | 1        |  | $        |    |         
|Obsolete Materials                          |  | $        | 98  |          | $ |         |  | $        |    |         
|For The Year Ended December 31, 2000        |  |          |     |          |   |          |  |          |     |         
|Allowance for Uncollectible Accounts        |  | $        | 49  |          | $ | 46       |  | $        | 11  |         
|Reserve for:
Merger-Related Costs           |  | $        |    |          | $ |         |  | $        | 149 |         
|Injuries and Damages                        |  | $        | 55  |          | $ | 10       |  | $        | 5   |         
|Environmental Investigation and Remediation |  | $        | 100 |          | $ | 26       |  | $        |    |         
|Obsolete Materials                          |  | $        | 27  |          | $ | 57       |  | $        | 19  |         

---

266

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| |  | 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                                                  



267

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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
|------------------------------------------- |  | -------- | --- | -------- | - | -------- |  | -------- | - | -------- | - | --------
|
|
|For The Year Ended December 31, 2002        |  |          |     |          |   |          |  |          |   |          |   |         
|Allowance for Uncollectible Accounts        |  | $        | 110 |          | $ | 45       |  | $        |  |          | $ | 83      
|Reserve for:                                |  |          |     |          |   |          |  |          |   |          |   |         
|Injuries and Damages                        |  | $        | 25  |          | $ | 10       |  | $        |  |          | $ | 11      
|Environmental Investigation and Remediation |  | $        | 37  |          | $ | 3        |  | $        | 6 |          | $ | 6       
|Obsolete Materials                          |  | $        | 1   |          | $ |         |  | $        |  |          | $ | 1       
|For The Year Ended December 31, 2001        |  |          |     |          |   |          |  |          |   |          |   |         
|Allowance for Uncollectible Accounts        |  | $        | 131 |          | $ | 69       |  | $        |  |          | $ | 67      
|Reserve for:                                |  |          |     |          |   |          |  |          |   |          |   |         
|Injuries and Damages                        |  | $        | 21  |          | $ | 13       |  | $        |  |          | $ | 9       
|Environmental Investigation and Remediation |  | $        | 54  |          | $ |         |  | $        |  |          | $ | 2       
|Obsolete Materials                          |  | $        | 3   |          | $ | 6        |  | $        |  |          | $ | 7       
|For The Year Ended December 31, 2000        |  |          |     |          |   |          |  |          |   |          |   |         
|Allowance for Uncollectible Accounts        |  | $        | 112 |          | $ | 68       |  | $        |  |          | $ | 49      
|Reserve for:                                |  |          |     |          |   |          |  |          |   |          |   |         
|Injuries and Damages                        |  | $        | 23  |          | $ | 7        |  | $        |  |          | $ | 9       
|Environmental Investigation and Remediation |  | $        | 57  |          | $ |         |  | $        |  |          | $ | 3       

---

268

---



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
|------------------------------------------- |  | -------- | -- | -------- | - | -------- |  | -------- | --- | -------- | - | --------
|
|
|For The Year Ended December 31, 2002        |  |          |    |          |   |          |  |          |     |          |   |         
|Allowance for Uncollectible Accounts        |  | $        | 17 |          | $ | 26       |  | $        |    |          | $ | 21      
|Reserve for:                                |  |          |    |          |   |          |  |          |     |          |   |         
|Merger Related Costs                        |  | $        | 31 |          | $ |         |  | $        | (2  | )        | $ | 22      
|Injuries and Damages                        |  | $        | 12 |          | $ | 25       |  | $        |    |          | $ | 9       
|Environmental Investigation and Remediation |  | $        | 14 |          | $ |         |  | $        | 7   | (e)      | $ | 6       
|Obsolete Materials                          |  | $        | 12 |          | $ | 10       |  | $        | 3   |          | $ | 12      
|For The Year Ended December 31, 2001        |  |          |    |          |   |          |  |          |     |          |   |         
|Allowance for Uncollectible Accounts        |  | $        | 2  |          | $ | 16       |  | $        |    |          | $ | 1       
|Reserve for:                                |  |          |    |          |   |          |  |          |     |          |   |         
|Merger Related Costs                        |  | $        | 50 |          | $ |         |  | $        | (10 | )        | $ | 9       
|Injuries and Damages                        |  | $        | 8  |          | $ |         |  | $        | 4   |          | $ |        
|Environmental Investigation and Remediation |  | $        | 15 |          | $ |         |  | $        |    |          | $ | 1       
|Obsolete Materials                          |  | $        | 79 |          | $ | 11       |  | $        |    |          | $ | 78      
|For The Year Ended December 31, 2000        |  |          |    |          |   |          |  |          |     |          |   |         
|Allowance for Uncollectible Accounts        |  | $        |   |          | $ | 2        |  | $        |    |          | $ |        
|Reserve for:                                |  |          |    |          |   |          |  |          |     |          |   |         
|Merger Related Costs                        |  | $        |   |          | $ |         |  | $        |    |          | $ |        
|Injuries and Damages                        |  | $        |   |          | $ |         |  | $        | 8   |          | $ |        
|Environmental Investigation and Remediation |  | $        | 16 |          | $ |         |  | $        |    |          | $ | 1       
|Obsolete Materials                          |  | $        | 1  |          | $ |         |  | $        | 78  |          | $ |        

---

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.

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

---

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                                                                                                                                                                                                                                                                                       
|      |  | May 1, 1927                                                                                                                                                                                                                                                                                       
|      |  | March 1, 1937                                                                                                                                                                                                                                                                                     
|      |  | December 1, 1941                                                                                                                                                                                                                                                                                  
|      |  | November 1, 1944                                                                                                                                                                                                                                                                                  
|      |  | December 1, 1946                                                                                                                                                                                                                                                                                  
|      |  | September 1, 1957                                                                                                                                                                                                                                                                                 
|      |  | May 1, 1958                                                                                                                                                                                                                                                                                       
|      |  | March 1, 1968                                                                                                                                                                                                                                                                                     
|      |  | March 1, 1981                                                                                                                                                                                                                                                                                     
|      |  | March 1, 1981                                                                                                                                                                                                                                                                                     
|      |  | December 1, 1984                                                                                                                                                                                                                                                                                  
|      |  | April 1, 1991                                                                                                                                                                                                                                                                                     
|      |  | December 1, 1991                                                                                                                                                                                                                                                                                  
|      |  | June 1, 1992                                                                                                                                                                                                                                                                                      
|      |  | March 1, 1993                                                                                                                                                                                                                                                                                     
|      |  | May 1, 1993                                                                                                                                                                                                                                                                                       
|      |  | May 1, 1993                                                                                                                                                                                                                                                                                       
|      |  | August 15, 1993                                                                                                                                                                                                                                                                                   
|      |  | May 1, 1995                                                                                                                                                                                                                                                                                       
|      |  | September 15, 2002                                                                                                                                                                                                                                                                                
|      |  | October 1, 2002                                                                                                                                                                                                                                                                                   
|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                                                                                                                                                                                                                                                     
|      |  | August 1, 1946                                                                                                                                                                                                                                                  
|      |  | April 1, 1953                                                                                                                                                                                                                                                   
|      |  | March 31, 1967                                                                                                                                                                                                                                                  
|      |  | April 1,1967                                                                                                                                                                                                                                                    
|      |  | February 28, 1969                                                                                                                                                                                                                                               
|      |  | May 29, 1970                                                                                                                                                                                                                                                    
|      |  | June 1, 1971                                                                                                                                                                                                                                                    
|      |  | April 1, 1972                                                                                                                                                                                                                                                   
|      |  | May 31, 1972                                                                                                                                                                                                                                                    
|      |  | June 15, 1973                                                                                                                                                                                                                                                   
|      |  | May 31, 1974                                                                                                                                                                                                                                                    
|      |  | June 13, 1975                                                                                                                                                                                                                                                   
|      |  | May 28, 1976                                                                                                                                                                                                                                                    
|      |  | June 3, 1977                                                                                                                                                                                                                                                    
|      |  | May 17, 1978                                                                                                                                                                                                                                                    
|      |  | August 31, 1978                                                                                                                                                                                                                                                 
|      |  | June 18, 1979                                                                                                                                                                                                                                                   
|      |  | June 20, 1980                                                                                                                                                                                                                                                   
|      |  | April 16, 1981                                                                                                                                                                                                                                                  
|      |  | April 30, 1982                                                                                                                                                                                                                                                  
|      |  | April 15, 1983                                                                                                                                                                                                                                                  
|      |  | April 13, 1984                                                                                                                                                                                                                                                  
|      |  | April 15, 1985                                                                                                                                                                                                                                                  
|      |  | April 15, 1986                                                                                                                                                                                                                                                  
|      |  | June 15, 1990                                                                                                                                                                                                                                                   
|      |  | October 1, 1991                                                                                                                                                                                                                                                 
|      |  | October 15, 1991                                                                                                                                                                                                                                                
|      |  | May 15, 1992                                                                                                                                                                                                                                                    
|      |  | September 15, 1992                                                                                                                                                                                                                                              
|      |  | February 1, 1993                                                                                                                                                                                                                                                
|      |  | April 1, 1993                                                                                                                                                                                                                                                   
|      |  | April 15, 1993                                                                                                                                                                                                                                                  
|      |  | June 15, 1993                                                                                                                                                                                                                                                   
|      |  | July 15, 1993                                                                                                                                                                                                                                                   
|      |  | January 15, 1994                                                                                                                                                                                                                                                
|      |  | December 1, 1994                                                                                                                                                                                                                                                
|      |  | June 1, 1996                                                                                                                                                                                                                                                    
|      |  | March 1, 2002                                                                                                                                                                                                                                                   
|      |  | May 20, 2002                                                                                                                                                                                                                                                    
|      |  | June 1, 2002                                                                                                                                                                                                                                                    
|      |  | October 7, 2002                                                                                                                                                                                                                                                 
|      |  | January 13, 2003                                                                                                                                                                                                                                                
|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                                                                                                                                                                                                                                                                                               
|        |  | September 1, 1987                                                                                                                                                                                                                                                                                         
|        |  | January 1, 1997                                                                                                                                                                                                                                                                                           
|        |  | September 1, 2000                                                                                                                                                                                                                                                                                         
|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

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|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

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|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                                                                                                                                                                                             

---

279

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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:                | 
|                   | 
|                   | 

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. ROWEJohn W. Rowe                 |  | Chairman, President and Chief Executive Officer
(Principal Executive Officer)     
|/s/ROBERT S. SHAPARDRobert S. Shapard       |  | Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
|/s/MATTHEW F. HILZINGERMatthew 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. ROWEName: John W. Rowe
Title: Chairman, President and Chief Executive Officer |  | March 21, 2003

280

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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.

|COMMONWEALTH EDISON COMPANY | 
|--------------------------- | 
|                            | 
|By:                         | 
|                            | 
|                            | 

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. ROWEJohn W. Rowe               |  | Chairman, President and Chief Executive Officer, Exelon and Director                      
|/s/PAMELA B. STROBELPamela B. Strobel     |  | Chair
(Principal Executive Officer)                                                       
|/s/ROBERT S. SHAPARDRobert S. Shapard     |  | Executive Vice President and Chief Financial Officer, Exelon
(Principal Financial Officer)
|/s/FRANK M. CLARKFrank M. Clark           |  | President and Director                                                                    
|/s/KATHRYN M. HOUTSMAKathryn M. Houtsma   |  | Vice President, Finance
(Principal Accounting Officer)                                    
|/s/RUTH ANN M. GILLISRuth Ann M. Gillis   |  | Director                                                                                  
|/s/KENNETH G. LAWRENCEKenneth G. Lawrence |  | Director                                                                                  

281

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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.

|PECO ENERGY COMPANY | 
|------------------- | 
|                    | 
|By:                 | 
|                    | 
|                    | 

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. ROWEJohn W. Rowe               |  | Chairman, President and Chief Executive Officer, Exelon and Director                      
|/s/PAMELA B. STROBELPamela B. Strobel     |  | Chair
(Principal Executive Officer)                                                       
|/s/ROBERT S. SHAPARDRobert S. Shapard     |  | Executive Vice President and Chief Financial Officer, Exelon
(Principal Financial Officer)
|/s/KENNETH G. LAWRENCEKenneth G. Lawrence |  | President and Director                                                                    
|/s/FRANK F. FRANKOWSKIFrank F. Frankowski |  | Vice President, Finance
(Principal Accounting Officer)                                    
|/s/RUTH ANN M. GILLISRuth Ann M. Gillis   |  | Director                                                                                  

282

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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 GENERATION COMPANY, LLC | 
|------------------------------ | 
|                               | 
|By:                            | 
|                               | 
|                               | 

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. ROWEJohn 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. SHAPARDRobert S. Shapard           |  | Executive Vice President and Chief Financial Officer, Exelon
(Principal Financial and Accounting Officer)
|/s/THOMAS H. WEIRThomas H. Weir                 |  | Controller                                                                                               

283

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CERTIFICATION PURSUANT TO RULE 13A-14 AND 15D-14  OF THE SECURITIES AND EXCHANGE ACT OF 1934

I,
John W. Rowe, certify that:

|Date: March 21, 2003 |  | /s/JOHN W. ROWEChairman, 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:

|Date: March 21, 2003 |  | /s/ROBERT S. SHAPARDExecutive 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:

|Date: March 21, 2003 |  | /s/PAMELA B. STROBELChair
(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:

|Date: March 21, 2003 |  | /s/ROBERT S. SHAPARDExecutive 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:

|Date: March 21, 2003 |  | /s/PAMELA B. STROBELChair
(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:

|Date: March 21, 2003 |  | /s/ROBERT S. SHAPARDExecutive 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:

|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:

|Date: March 21, 2003 |  | /s/ROBERT S. SHAPARDExecutive Vice President and Chief Financial Officer, Exelon
(Principal Financial Officer)
|-------------------- |  | --------------------------------------------------------------------------------------------------------------

291

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