Exelon Generation 10K 2003 Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the Fiscal Year Ended December 31, 2003

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


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

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

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

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

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


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

PECO ENERGY COMPANY:
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 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

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

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

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


Exelon Corporation	Yes x	No ¨
Commonwealth Edison Company	Yes ¨	No x
PECO Energy Company	Yes ¨	No x
Exelon Generation Company, LLC	Yes ¨	No x

The estimated aggregate market value of the voting and non-voting common equity held by nonaffiliates of each registrant as of June 30, 2003, was as follows:


Exelon Corporation Common Stock, without par value		$19,484,998,248
Commonwealth Edison Company Common Stock, $12.50 par value		No established market
PECO Energy Company Common Stock, without par value		None
Exelon Generation Company, LLC		Not applicable

The number of shares outstanding of each registrant’s common stock as of January 31, 2004 was as follows:


Exelon Corporation Common Stock, without par value		329,235,372
Commonwealth Edison Company Common Stock, $12.50 par value		127,016,494
PECO Energy Company Common Stock, without par value		170,478,507
Exelon Generation Company, LLC		Not applicable

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Exelon Corporation’s Current Report on Form 8-K dated February 20, 2004 containing consolidated financial statements and related information for the year ended December 31, 2003, 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 to be filed prior to April 29, 2004, 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 29, 2004, relating to its annual meeting of shareholders, are incorporated by reference into Part III of this Annual Report on Form 10-K.

TABLE OF CONTENTS


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

PART I
ITEM 1.	BUSINESS		2
		General	2
		Energy Delivery	3
		Exelon Generation Company, LLC	10
		Enterprises	24
		Employees	25
		Environmental Regulation	26
		Other Subsidiaries of ComEd and PECO with Publicly Held Securities	29
		Executive Officers of the Registrants	31
ITEM 2.	PROPERTIES		33
		Energy Delivery	33
		Exelon Generation Company, LLC	35
ITEM 3.	LEGAL PROCEEDINGS		37
		Commonwealth Edison Company	37
		PECO Energy Company	37
		Exelon Generation Company, LLC	37
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		39

PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS		40
ITEM 6.	SELECTED FINANCIAL DATA		41
		Exelon Corporation	41
		Commonwealth Edison Company	41
		PECO Energy Company	43
		Exelon Generation Company, LLC	44
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		45
		Exelon Corporation	45
		Commonwealth Edison Company	52
		PECO Energy Company	74
		Exelon Generation Company, LLC	94
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		120
		Exelon Corporation	120
		Commonwealth Edison Company	120
		PECO Energy Company	121
		Exelon Generation Company, LLC	122
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		134
		Exelon Corporation	134
		Commonwealth Edison Company	135
		PECO Energy Company	170
		Exelon Generation Company, LLC	201
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		245


			Page No.
ITEM 9A.	CONTROLS AND PROCEDURES		245
		Exelon Corporation	245
		Commonwealth Edison Company	245
		PECO Energy Company	246
		Exelon Generation Company, LLC	246

PART III
ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT		247
		Exelon Corporation	247
		Commonwealth Edison Company	247
		PECO Energy Company	248
		Exelon Generation Company, LLC	248
ITEM 11.	EXECUTIVE COMPENSATION		249
		Exelon Corporation	249
		PECO Energy Company	249
		Commonwealth Edison Company	249
		Exelon Generation Company, LLC	249
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		263
		Exelon Corporation	263
		Commonwealth Edison Company	264
		PECO Energy Company	265
		Exelon Generation Company, LLC	265
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS		266
		Exelon Corporation	266
		Commonwealth Edison Company	266
		PECO Energy Company	266
		Exelon Generation Company, LLC	266
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES		266
		Exelon Corporation	266
		Commonwealth Edison Company	266
		PECO Energy Company	267
		Exelon Generation Company, LLC	267

PART IV
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K		269

SIGNATURES			288
		Exelon Corporation	288
		Commonwealth Edison Company	289
		PECO Energy Company	290
		Exelon Generation Company, LLC	291

FILING FORMAT

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

FORWARD-LOOKING STATEMENTS

Except for the historical information contained herein, certain of the matters discussed in this Report are forward-looking statements, within the meaning of the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by a registrant include those factors discussed herein, including those discussed in (a) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Business Outlook and the Challenges in Managing Our Business for each of Exelon, ComEd, PECO and Generation, (b) ITEM 8. Financial Statements and Supplementary Data: Exelon - Note 19, ComEd – 15, PECO – Note 14 and Generation – Note 13 and (c) other factors discussed in filings with the United States Securities and Exchange Commission (SEC) by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

WHERE TO FIND MORE INFORMATION

The public may read and copy any reports or other information that 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 atwww.sec.gov and Exelon’s website atwww.exeloncorp.com.

The Exelon corporate governance guidelines and the charters of the standing committees of its Board of Directors, together with the Exelon Code of Business Conduct and additional information regarding Exelon’s corporate governance, are available on Exelon’s website atwww.exeloncorp.com and will be made available, without charge, in print to any shareholder who requests such documents from Katherine K. Combs, Vice President and Corporate Secretary, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.

PART I

ITEM 1. BUSINESS

General

Exelon Corporation (Exelon), a registered public utility holding company, through its subsidiaries, operates in three business segments – Energy Delivery, Generation and Enterprises – as described below. See Note 21 of the Notes to Consolidated Financial Statements for further segment information. In addition to Exelon’s three business segments, Exelon Business Services Company (BSC), a subsidiary of Exelon, provides Exelon and its subsidiaries with financial, human resource, legal, information technology, supply management and corporate governance services.

Exelon was incorporated in Pennsylvania in February 1999. Exelon’s principal executive offices are located at 10 South Dearborn Street, Chicago, Illinois 60603, and its telephone number is 312-394-7398.

Energy Delivery

Exelon’s energy delivery business consists of the regulated sale of electricity and distribution and transmission services by Commonwealth Edison Company (ComEd) in northern Illinois and by PECO Energy Company (PECO) in southeastern Pennsylvania and the regulated sale of natural gas and distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia.

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

Exelon’s generation business consists of the owned and contracted for electric generating facilities and energy marketing operations of Exelon Generation Company, LLC (Generation), a 50% interest in Sithe Energies, Inc. (Sithe) and, effective January 1, 2004, the competitive retail sales business of Exelon Energy Company.

Generation was formed in 2000 as a Pennsylvania limited liability company. Generation began operations as a result of a corporate restructuring effective January 1, 2001 in which Exelon separated its generation and other competitive business from its regulated energy delivery business at ComEd and PECO. Generation’s principal executive offices are located at 300 Exelon Way, Kennett Square, Pennsylvania 19348, and its telephone number is 610-765-6900.

Enterprises

Exelon’s enterprise business consists primarily of the energy services business of Exelon Services, Inc. (Exelon Services), the district cooling business of Exelon Thermal Holdings, Inc. (Thermal), the electrical contracting business of F&M Holdings, Inc., a communications joint venture and other investments weighted towards the communications, energy services and retail services industries. Effective January 1, 2004, Enterprises competitive retail sales business, Exelon Energy Company, became part of Generation. Exelon continues to pursue opportunities to sell other Enterprises businesses.

Federal and State Regulation

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). ComEd, PECO and Generation are electric utilities under the Federal Power Act subject to regulation by the Federal Energy Regulatory Commission (FERC). Specific operations of Exelon are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the United States Nuclear Regulatory Commission (NRC).

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 United States 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 under PUHCA through March 31, 2004 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. As of December 31, 2003, there was $2.0 billion of financing authority remaining under the SEC order, and Exelon had $1.9 billion of guarantees outstanding subject to PUHCA restrictions. On December 22, 2003, Exelon filed an application requesting financing authorization in an aggregate amount not to exceed $8 billion for a new authorization period, April 1, 2004 through April 15, 2007. 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 the 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. The service territory includes the City of Chicago (Chicago), an area of about 225 square miles with an estimated population of three million. ComEd has approximately 3.6 million customers.

ComEd’s franchises are sufficient to permit it to engage in the business it now conducts. ComEd’s franchise rights are generally nonexclusive rights documented in agreements and, in some cases, certificates of public convenience issued by the ICC. With few exceptions, the franchise rights have stated expiration dates ranging from 2004 to 2060 and subsequent years.

PECO is engaged principally in the purchase, transmission, distribution and sale of electricity to residential, commercial and industrial customers in southeastern Pennsylvania and in the purchase, distribution and sale of natural gas to residential, commercial and industrial customers in the Pennsylvania counties surrounding the City of Philadelphia. PECO is subject to extensive regulation by the PUC as to electric and gas rates, the issuances of

securities and certain other aspects of PECO’s operations. PECO is also subject to regulation by the FERC as to transmission rates, gas pipelines 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 3.9 million, including 1.5 million in the City of Philadelphia. Natural gas service is supplied in an approximate 1,900 square mile area in southeastern Pennsylvania adjacent to Philadelphia, with a population of approximately 2.4 million. PECO delivers electricity to approximately 1.5 million customers and natural gas to approximately 460,000 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.

Energy Delivery’s kilowatthour (kWh) sales and load of electricity are generally higher during the summer periods and winter periods, when temperature extremes create demand for either summer cooling or winter heating. ComEd’s highest peak load experienced to date occurred on August 21, 2003 and was 22,054 megawatts (MWs); and the highest peak load experienced to date during a winter season occurred on January 6, 2004 and was 15,205 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 15, 2004 and was 6,396 MWs.

PECO’s gas sales are generally higher during the winter periods when temperature extremes create demand for winter heating. PECO’s highest daily gas send out experienced to date occurred on January 17, 2000 and was 718 million cubic feet (mmcf).

Retail Electric Services

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

Under Illinois and Pennsylvania legislation, ComEd and PECO are required to provide generation services to customers who do not or cannot choose an alternative supplier. Provider of last resort (POLR) obligations refer to the obligation of a utility to provide generation services (i.e., power and energy) to those customers who do not take service from an alternative generation supplier or who choose to come back to the utility after taking service from an alternative supplier. Because the choice generally lies with the customer, POLR obligations make it difficult for the utility to predict and plan for the level of customers and associated energy demand. If POLR 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 the utilities. ComEd and PECO continue to be obligated to provide a reliable delivery system under cost-based rates.

ComEd. All of 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. As of December 31, 2003, no ARES had sought approval from the

ICC, and no electric utilities have chosen, to enter the residential market for the supply of electricity in ComEd’s service territory. At December 31, 2003, approximately 20,300 non-residential customers, representing approximately 31% 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 to ComEd. ComEd is unable to predict the long-term impact of customer choice on its results of operations.

On November 14, 2002, the ICC allowed ComEd to revise its POLR obligation to be the back-up energy supplier at market-based rates for customers with energy demands of at least three megawatts. About 370 of ComEd’s largest energy customers are affected, representing an aggregate of approximately 2,500 megawatts, and will not have a right to take bundled service after June 2006 or to come back to bundled rates if they choose an alternative supplier. These customers accounted for 10% of ComEd’s 2003 MWh deliveries. On March 28, 2003, the ICC approved changes to ComEd’s 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. An appeal to each of the ICC’s orders is pending and ComEd cannot predict the outcome of those appeals.

The parties to a March 2003 agreement with various Illinois electric retail market suppliers, key customer groups and governmental parties regarding several matters affecting ComEd’s rates for electric service have committed, if specified market conditions exist, not to oppose a process initiated in June 2004 or thereafter for achieving a similar competitive declaration for customers having energy demands of one to three megawatts.

In addition to retail competition for generation services, the Illinois legislation provided for residential base rate reductions, a sharing with customers of any earnings over a defined threshold and a base rate freeze, reflecting the residential base rate reductions, through January 1, 2007. A 15% residential base rate reduction became effective on August 1, 1998, and a further 5% residential base rate reduction became effective October 1, 2001. A utility may request a rate increase during the rate freeze period only when necessary to ensure the utility’s financial viability. Under the Illinois legislation, if the two-year average of the earned return on common equity of a utility through December 31, 2006 exceeds an established threshold, one-half of the excess earnings must be refunded to customers. The threshold rate of return on common equity is based on a two-year average of the Monthly Treasury Bond Long-Term Average Rates (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 accounting principles generally accepted in the United States (GAAP) and reflect the amortization of regulatory assets. As a result of the Illinois legislation, at December 31, 2003, ComEd had a regulatory asset with an unamortized balance of $131 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 2003, 2002 or 2001 and does not currently expect to trigger the earnings sharing provisions in the years 2004 through 2006.

ComEd expects its capital expenditures will exceed depreciation on its rate base assets through at least 2004. 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.

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. An extension of this contract for 2005 and 2006 has been agreed to by ComEd and Generation with substantially the same terms as the PPA currently in effect, except for the prices for energy which were reset to reflect the current rates at the time the extension was agreed to. This extension must still be filed with the ICC. Subsequent to 2006, ComEd will obtain all of its supply from market sources, which could include Generation.

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

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 addressed, among other things, issues related to ComEd’s delivery services rate proceeding, market value index proceeding, the process for competitive service declarations for large-load customers and an amendment and extension of the PPA with Generation. During the second quarter of 2003, the ICC issued orders consistent with the Agreement, which is now effective.

The Agreement provides for a modification of the methodology used to determine ComEd’s market value energy credit. That credit is used to determine the price for specified market-based rate offerings and the amount of the CTC that ComEd is allowed to collect from customers who select an ARES or the PPO. The credit was adjusted upwards through agreed upon “adders” which took effect in June 2003 and has had and will continue to have the effect of reducing ComEd’s CTC charges to customers. Prior to the Agreement, all CTC charges were subject to annual mid-year adjustments based on the forward market prices for on-peak energy and historical market prices for off-peak energy. The Agreement provides that the annual market price adjustment will reflect forward market prices for energy, rather than historical, and allows customers an option to lock in current levels of CTC charges for multi-year periods during the regulatory transition period ending in 2006. These changes provide customers and suppliers greater price certainty and have resulted in an increase in the number of customers electing to purchase energy from alternate suppliers.

The annual market price adjustments to the CTC effective in June 2002 and the impacts of the Agreement in June 2003 had the effect of significantly increasing the CTC charge in June 2002 and subsequently significantly reducing the CTC charge in June 2003. In 2003 and 2002, ComEd collected $304 million and $306 million in CTC revenue, respectively. Based on the changes in the CTC as part of the Agreement and on current assumptions about the competitive price of delivered energy and customers’ choice of electric supplier, ComEd estimates that CTC revenue will be approximately $180 million to $200 million in each of the years 2004 through 2006.

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, 2003, approximately 20% of PECO’s residential load, 24% of its small commercial and industrial load and 5% of its large commercial and industrial load were purchasing generation service from alternative generation suppliers. Customers who purchase energy from an alternative generation supplier continue to pay a delivery charge to PECO.

In addition to retail competition for generation services, PECO’s 1998 settlement of its restructuring case mandated by the Competition Act established caps on generation and distribution rates. The 1998 settlement also

authorized PECO to recover $5.3 billion of stranded costs and to securitize up to $4.0 billion of its stranded cost recovery, which was subsequently increased to $5.0 billion.

Under the 1998 settlement, PECO’s distribution rates were capped through June 30, 2005 at the level in effect on December 31, 1996. Generation rates, consisting of the charge for stranded cost recovery and a shopping credit or capacity and energy charge, were capped through December 31, 2010. For 2003, the generation rate cap was $0.0698 per kWh, increasing to $0.0751 per kWh in 2006 and $0.0801 per kWh in 2007. The rate caps are subject to limited exceptions, including significant increases in Federal or state taxes or other significant changes in law or regulations that would not allow PECO to earn a fair rate of return. Under the settlement agreement entered into by PECO in 2000 relating to the PUC’s approval of the merger among PECO, Unicom Corporation (Unicom), the former parent company of ComEd, and Exelon (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. The remaining required rate reductions are $40 million per year in 2004 and 2005.

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.

PECO has been authorized by the PUC to recover stranded costs of $5.3 billion over a twelve-year period ending December 31, 2010, with a return on the unamortized balance of 10.75%. The following table shows PECO’s allowed recovery of stranded costs, and amortization of the associated regulatory asset, for the years 2004 through 2010 as authorized by the PUC 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. 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 reconciling adjustments are made quarterly or monthly as needed.

PECO Estimated CTC Revenue and Annual Stranded Cost Amortization per the Electric Restructuring Settlement:


Year	Estimated CTC Revenue		Estimated Stranded Cost Amortization
2003 (Actual)	$	818	$	336
2004		812		367
2005		808		404
2006		903		550
2007		910		619
2008		917		697
2009		924		783
2010		932		880

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 1998 settlement of PECO’s restructuring case established market share thresholds (MST) to promote competition. The MST requirements provided that if, as of January 1, 2003, less than 50% of residential and commercial customers have chosen an alternative electric generation supplier, the number of customers sufficient to meet the MST shall be randomly selected and assigned to an alternative electric generation supplier through a PUC-determined process. On January 1, 2003, the number of customers choosing an alternative electric generation supplier did not meet the MST. As a result of a PUC-approved auction process, approximately 64,000 small commercial and industrial customers and 267,000 residential customers were selected to participate in the MST program of which approximately 50,000 and 194,000 customers enrolled with alternative electric generation suppliers in May 2003 and December 2003, respectively. Any customer transferred has the right to return to PECO at any time. Exelon and PECO do not expect the transfer of PECO customers pursuant to the MST plan to have a material impact on their respective results of operations, financial positions or cash flows.

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.

Transmission Services

Energy Delivery provides wholesale and unbundled retail transmission service under rates established by the FERC. The FERC has used its regulation of transmission to encourage competition for wholesale generation services and the development of regional structures to facilitate regional wholesale markets. Under the FERC’s open transmission access policy promulgated in Order No. 888, PECO and ComEd, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates. Under the FERC’s Order No. 889, PECO and ComEd are required to comply with the FERC’s Standards of Conduct regulation, as amended, governing the communication of non-public information between the transmission owner’s transmission employees and wholesale merchant employees or the employees of any energy affiliate of the transmission owner. The FERC recently issued Order No. 2004, amending the Standards of Conduct regulation. The amendments do not detrimentally impact Exelon’s business.

In December 1999, the 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.

Order 2000 and the proposed wholesale market platform 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. Under the proposed rule making, 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 would remain responsible for maintaining and physically operating their transmission facilities. The FERC has also issued proposals to encourage FERC-jurisdictional transmission owners to develop RTOs, independent control of the transmission grid and expansion of the transmission grid by providing enhanced returns on equity for transmission assets.

Order 2000 has not led to the rapid development of RTOs and the FERC has not yet finalized its standard market proposal. 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.

PJM Interconnection, LLC (PJM) is the independent system operator and the FERC-approved RTO for the Mid-Atlantic region in which it operates. PJM is the transmission provider under, and the administrator of, the PJM Open Access Transmission Tariff (PJM Tariff), operates the PJM Interchange Energy Market and Capacity Credit Markets, and conducts the day-to-day operations of the bulk power system of the PJM region. PECO’s transmission system is currently under the control of PJM, and ComEd has taken steps to place its transmission system under PJM’s control. Under the PJM tariff, transmission service is provided on a region-wide, open-access basis using the transmission facilities of the PJM members at rates based on the costs of transmission service.

ComEd.On April 1, 2003, ComEd received approval from the FERC to transfer control of its transmission assets to PJM. The FERC also accepted for filing the amended PJM Tariff to reflect the inclusion of ComEd and other new members, subject to a compliance filing and to hearing on certain issues. On June 2, 2003, ComEd began receiving electric transmission reservation services from PJM and transferred control of ComEd’s Open Access Same Time Information System to PJM. Although full integration of ComEd’s transmission assets into PJM’s energy market structures was scheduled to occur in November 2003, that date has been delayed due to the August 14, 2003 power blackout in the Northeast United States and Canada. PJM announced that it will conduct an investigation of that blackout and will apply any lessons learned from that investigation to this integration. After resolution of these matters and completion of certain implementation work necessary to integrate ComEd into PJM, ComEd expects to transfer functional control of its transmission assets to PJM and to integrate fully into PJM’s energy market structures during May 2004.

On November 10, 2003, the FERC issued an order allowing ComEd to put into effect beginning April 12, 2004, subject to refund and rehearing, new transmission rates designed to reflect nearly $500 million of infrastructure improvements made since 1998. However, because of the Illinois retail rate freeze and the method for calculating CTCs, the increase is not expected to significantly increase operating revenues. ComEd is unable to predict the ultimate outcome of the associated rehearing or settlement negotiations.

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

Gas

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

The PUC established, through regulated proceedings, the rates that PECO may charge for gas service in Pennsylvania. PECO’s purchased gas cost rates, which represent a portion of total rates, are subject to quarterly adjustments designed to recover or refund the difference between the actual cost of purchased gas and the amount included in rates.

Approximately 30% of PECO’s current total yearly throughput is supplied by third parties. Gas 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 22.0 million dekatherms of underground storage through service agreements. Natural gas from underground storage represents approximately 34% of PECO’s 2003-2004 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 2004:


(in millions)	ComEd		PECO
Transmission and distribution	$	586	$	178
Gas		—		53
Other		30		8

Total	$	616	$	239

Approximately 50% of ComEd’s 2004 budgeted capital expenditures and 60% of PECO’s 2004 budgeted capital expenditures are for additions to or upgrades of existing facilities, including improvements to reliability. The remainder of the capital expenditures support customer and load growth.

Generation

Generation is one of the largest competitive electric generation companies in the United States, as measured by owned and controlled MWs. Generation combines its large generation fleet with an experienced wholesale power marketing operation.

At December 31, 2003, Generation owned generation assets in the Northeast, Mid-Atlantic, Midwest and Texas regions with a net capacity of 28,492 MWs, including 16,959 MWs of nuclear capacity. In December 2003, Generation purchased British Energy plc’s (British Energy) 50% interest in AmerGen Energy Company, LLC (AmerGen) for $276.5 million. AmerGen is now a wholly owned subsidiary of Generation. Generation’s ownership interests include 3,145 MWs of capacity owned by Boston Generating, LLC (Boston Generating), a project subsidiary of Exelon New England formerly known as Exelon Boston Generating, LLC of which 2,851 MWs is currently available for commercial operations. Generation controls another 12,703 MWs of capacity in the Midwest, Southeast and South Central regions through long-term contracts.

On November 25, 2003, Generation, Reservoir Capital Group (Reservoir) and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe with put and call options that could result in either party owning Sithe outright. While Generation’s intent is to fully divest Sithe, the timing of the put and call options vary by acquirer and can extend through March 2006. The pricing of the put and call options is dependent on numerous factors, such as the acquirer, date of acquisition and assets owned by Sithe at the time of exercise. Currently, Sithe has a total generating capacity of 1,097 MWs in operation and 228 MWs under construction. See further discussion of these transactions in the Sithe section, which follows within this ITEM 1. Business – Generation.

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

Generating Resources

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


Type of Capacity		MWs
Owned generation assets (1,2)
Nuclear		16,959
Fossil (3)		9,925
Hydroelectric		1,608

Owned generation assets		28,492
Long-term contracts (4)		12,703
Sithe (2)		549

Available resources		41,744
Under construction (2)		114

Total generating resources		41,858

(1)	See ITEM 1. Business – Generation “Fuel” for sources of fuels used in electric generation.

(2)	Based on Generation’s 50% ownership of Sithe.

(3)	Includes 3,145 MWs of generating capacity owned by Boston Generating, of which 2,851 MWs is currently available for commercial operations.

(4)	Contracts range from 1 to 27 years.

The owned generating resources of Generation are located in the Midwest region (approximately 40% of capacity), the Mid-Atlantic region (approximately 39% of capacity), the Northeast region (approximately 12% of capacity) and the Texas region (approximately 9%). Sithe’s generating resources are primarily in New York. The remaining plants are located throughout North America.

In July 2003, Generation announced that it would transition out of its ownership of Boston Generating and the related projects and recorded an asset impairment charge of $945 million (before income taxes) associated with its decision. Boston Generating currently owns 3,145 MWs of generating capacity, of which 2,851 MWs is currently available for commercial operations, located in Massachusetts.

For a further discussion of Sithe and Boston Generating, see the Sithe and Boston Generating sections, which follow within this ITEM 1. Business – Generation.

Nuclear Facilities. Generation has ownership interests in 11 nuclear generating stations, consisting of 19 units with 16,959 MW of capacity. 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 2003, over 50% of Generation’s electric supply was generated from the nuclear generating facilities. During 2003 and 2002, the nuclear generating facilities operated by Generation operated at weighted average capacity factors of 93.4% and 92.7%, respectively.

Licenses. Generation has 40-year operating licenses from the NRC for each of its nuclear units. Generation applied to the NRC in January 2003 for extensions of the operating licenses of Dresden units 2 and 3 and the Quad Cities units. 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. Generation anticipates filing a request for a license extension for Oyster Creek and is currently evaluating the other AmerGen facilities for possible extension. Depreciation provisions are based on the estimated useful lives of the units, which assume the extension of these licenses for all of the non-AmerGen nuclear generating stations. Generation extended the depreciable lives of the AmerGen stations beginning in January 2004 concurrent with its initial full month of 100% ownership.

On May 7, 2003, the NRC announced that it had approved a twenty-year extension of the operating licenses for Peach Bottom Units 2 and 3. The original 40-year license for Peach Bottom Unit 2 was extended to 2033, and the Unit 3 license was extended to 2034.

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
Clinton	1	1987	2026
Dresden	2 3	1970 1971	2009 2011
LaSalle	1 2	1984 1984	2022 2023
Limerick	1 2	1986 1990	2024 2029
Oyster Creek	1	1969	2009
Peach Bottom	2 3	1974 1974	2033 2034
Quad Cities	1 2	1973 1973	2012 2012
Salem	1 2	1977 1981	2016 2020
Three Mile Island	1	1974	2014

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

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 20 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 2003 indicate that the performance indicators for Generation’s nuclear plants are all in the highest performance band, with the exception of one indicator for Dresden Unit 3, and one indicator for Braidwood Unit 1, both of which are still considered to be in an acceptable performance band within that indicator by the NRC.

Exelon does not know the impact that future terrorist attacks or threats of terrorism may have on the electric and gas industry in general and on Exelon in particular. Exelon has initiated security measures to safeguard its employees and critical operations from threats of terrorism and is actively participating in industry initiatives to identify methods to maintain the reliability of Exelon’s energy production and delivery systems. Generation has met or exceeded all security measures mandated by the NRC for nuclear plants. On a continuing basis, Exelon is evaluating enhanced security measures at certain critical locations, enhanced response and recovery plans and assessing long-term design changes and redundancy measures. Additionally, the energy industry is working with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems. These measures will involve additional expenses to develop and implement, but will provide increased assurances as to Exelon’s ability to 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 safely stores all SNF generated by nuclear generating facilities in on-site storage pools and, in the case of Peach Bottom, Oyster Creek and Dresden, some SNF has been placed in dry cask storage facilities. Not all of Generation’s SNF storage pools have sufficient storage capacity for the life of the plant. Generation is developing dry cask storage facilities, as necessary, to support operations.

As of December 31, 2003, Generation had 41,200 SNF assemblies (9,900 tons) stored on site in SNF pools and dry cask storage. On site dry cask storage in concert with on site storage pools is capable of meeting all current and future SNF storage requirements at Generation’s sites. The following table describes the current status of Generation’s SNF storage facilities:


Site	Date for loss of full core discharge
Dresden	Dry cask storage in operation
Quad Cities	2005
Byron	2011
LaSalle	2012
Braidwood	2013
Clinton	2006	(1)
Peach Bottom	Dry cask storage in operation
Limerick	2009
Oyster Creek	Dry cask storage in operation
TMI	Life of plant storage capable in SNF pool
Salem	2011

(1)	Plans to re-rack to increase SNF pool capacity to approximately 2014.

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 cask storage at its Dresden, Quad Cities, Peach Bottom and Oyster Creek Stations and its consideration of dry cask 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 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 June 2003, the court granted the Government’s motion to dismiss claims other than the breach of contract claims. The trial to determine damages has been set for November 2004.

In July 2000, PECO entered into an agreement (Amendment) with the DOE relating to Generation’s Peach Bottom nuclear generating units to address the DOE’s failure to begin removal of SNF in January 1998 as required by the Standard Contract. Under the Amendment, 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 Amendment also provided 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 the 2001 corporate restructuring.

In November 2000, eight utilities with nuclear power plants filed a Joint Petition for Review against the DOE with the United States Court of Appeals for the Eleventh Circuit seeking to invalidate that portion of the Amendment providing for credits to PECO against nuclear waste fund payments on the ground that such provision is a violation of the NWPA. In September 2002, the United States Court of Appeals for the Eleventh Circuit ruled that the fee adjustment provision of the Amendment violates the NWPA and therefore is null and void. The court did not hold that the Amendment 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 agreement would be rendered null and void, the original Peach Bottom Standard Contract would remain in effect and the parties would return to pre-agreement status. In August 2003, Generation received a letter from the DOE demanding repayment of $40 million of previously received credits from the Nuclear Waste Fund and $1.5 million of accrued interest expense. Generation reserved its ownership share of these amounts in the third quarter of 2003 and has continued to record an interest expense associated with the repayment demand. Generation is in discussions with the DOE regarding a new settlement agreement with a different funding mechanism.

The Standard Contract with the DOE also required 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, 2003, the unfunded liability for the one-time fee with interest was $867 million. The liabilities for SNF 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 2003.

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, 2004, the current limit is $10.9 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance (currently $300 million for each operating site) and the remaining $10.6 billion is provided through mandatory participation in a financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed a maximum charge per reactor per incident. Effective August 20, 2003, the maximum assessment for all nuclear operators per reactor per incident (including a 5% surcharge) increased from $89 million to $101 million, payable at no more than $10 million per reactor per incident per year. This assessment is subject to inflation and state premium taxes. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims. The Price-Anderson Act expired on August 1, 2002 and was subsequently extended to the end of 2003 by the U.S. Congress. Only facilities applying for NRC licenses subsequent to the expiration of the Price-Anderson Act are affected. Existing commercial generating facilities, such as those owned and operated by Generation, remain subject to the provisions of the Price-Anderson Act and are unaffected by its expiration.

Generation is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides property damage, decontamination and premature decommissioning insurance for each station for losses 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 $170 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 NEIL 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. Including the AmerGen sites, Generation’s maximum share of any assessment is $61 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.

For information regarding property insurance, see ITEM 2. Properties – Generation. Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained. Such losses could have a material adverse effect on Generation’s financial condition and results of operations.

Decommissioning.NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. Based on estimates of decommissioning costs for each of the nuclear facilities transferred to Generation from PECO as a result of the 2001 restructuring, the PUC permits PECO to collect from their customers and deposit in nuclear decommissioning trust funds maintained by Generation amounts which, together with earnings theron, will be used to decommission such nuclear facilities. As more fully described below, both ComEd and PECO are currently collecting amounts from rate payers, which are remitted to the trust funds maintained by Generation that will be used to decommission nuclear facilities. Upon adoption of SFAS No. 143, “Asset Retirement Obligations” (SFAS No. 143), Generation was required to re-measure its decommissioning liabilities at fair value and recorded an asset retirement obligation of $2.4 billion on January 1, 2003. Increases in the asset retirement obligation are recorded as operating and maintenance expense. At December 31, 2003, the asset retirement obligation recorded within Generation’s Consolidated Balance Sheet was $3.0 billion including amounts associated with the newly consolidated AmerGen units. 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.

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 ComEd’s customers. The ICC order also provides that any surplus funds after the nuclear stations are decommissioned must be refunded to ComEd’s customers. The ICC order has been upheld on appeal 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. In 2003, the PUC authorized an annual increase in PECO’s decommissioning cost recovery of approximately $4 million, increasing annual collections to $33 million per year. The amendment is consistent with provisions in PECO’s 1998 settlement of its restructuring case and the Merger settlement, which require PECO to update the cost of decommissioning every five years.

Generation believes that the amounts being remitted to it by ComEd and PECO, Generation’s nuclear decommissioning trust funds and the earnings on these funds will be sufficient to fully fund Generation’s

decommissioning obligations. See Critical Accounting Policies and Estimates within Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Generation for a further discussion of Nuclear Decommissioning.

AmerGen maintains decommissioning trust funds 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 fully fund its decommissioning obligations.

Zion, a two-unit nuclear generation station, and Dresden Unit 1 have permanently ceased power generation. Zion and Dresden Unit 1’s SNF is currently being stored in on-site storage pools and dry cask storage, respectively, until a permanent repository under the NWPA is completed. Generation has recorded a liability of $694 million at December 31, 2003, which represents the estimated cost of decommissioning Zion and Dresden Unit 1 in current year dollars. The majority of decommissioning expenditures are expected to occur primarily after 2013 and 2030 for Zion and Dresden Unit 1, respectively.

Fossil and Hydroelectric Facilities.

Fossil units include:

•

base-load units — the coal-fired units at Eddystone and Cromby and Generation’s interests in the Conemaugh Stations and Keystone;

•

intermediate units — the Cromby and Eddystone units and the Mystic 7 unit have dual fuel (oil/gas) capability; Handley, Mystic 8 and 9, Mountain Creek, New Boston, and Fore River are gas fueled stations; Wyman is an oil-fueled station; and

•

peaking units — oil- or gas-fired steam turbines, combustion turbines and internal combustion units at various locations.

Hydroelectric facilities include:

•

base-load units — the Conowingo run-of-river hydroelectric facility on the Susquehanna River in Harford County, Maryland; and

•

intermediate units — the Muddy Run pumped-storage hydroelectric facility in Lancaster County, Pennsylvania.

Generation operates all of its fossil and hydroelectric facilities other than La Porte, Keystone, Conemaugh and Wyman. In 2003, approximately 17% of Generation’s electric output was generated from Generation’s owned fossil and hydroelectric generating facilities. The majority of this output was dispatched to support Generation’s power marketing activities.

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 the FERC. The Muddy Run and Conowingo facilities have licenses that expire in September 2014. Generation is considering applying to the FERC for license extensions of 40 years for both plants, but the duration of any license extension will depend on then-current policies at the FERC. The processing of an extension to an existing hydroelectric license generally takes at least eight years.

Insurance.Generation does not carry business interruption insurance for its fossil and hydroelectric operations other than its coverage for Boston Generating. 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 Exelon and Generation’s financial condition and their results of operations. For information regarding property insurance, see ITEM 2. Properties – Generation.

Long-Term Contracts

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


Seller	Location	Expiration	Capacity (MWs)
Midwest Generation, LLC	Various in Illinois	2004	3,858
Kincaid Generation, LLC	Kincaid, Illinois	2013	1,158
Tenaska Georgia Partners, LP	Franklin, Georgia	2030	925
Tenaska Frontier, Ltd	Shiro, Texas	2020	830
Green Country Energy, LLC	Jenks, Oklahoma	2022	795
Others	Various	2004 to 2021	5,137

Total			12,703

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. In 2003, Generation took 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. On June 25, 2003, Generation notified Midwest Generation of its exercise of its call option under the Coal Generation PPA for 2004. Generation exercised its call option on 687 MWs of capacity for 2004 generated by Waukegan Unit 8 and Fisk Unit 19 and did not exercise its option on 578 MWs of capacity at Waukegan Unit 6, Crawford Unit 7, and Will County Unit 3. On October 1, 2003, Generation notified Midwest Generation of its exercise of certain termination options under the Collins and Peaking Unit Agreements, releasing 303 MWs for 2004, the fifth and final year of the contract. With the exercise of the termination options on the peaking plants in addition to the exercise of the options on the coal plants in June 2003, the contract with Midwest Generation has been finalized for 2004. Generation will take 1,696 MWs of non-option coal capacity, 687 MWs of option coal capacity, 1,084 MWs of Collins Station capacity and 391 MWs of peaking capacity from Midwest Generation in 2004. In total, Generation has retained 3,858 MWs of capacity under the terms of the three existing PPAs with Midwest Generation.

Federal Power Act

The Federal Power Act gives the 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 the FERC’s jurisdiction are required to file rate schedules with the FERC with respect to wholesale sales or transmission of electricity. Tariffs established under FERC regulation give Generation access to transmission lines that enable it to participate in competitive wholesale markets.

Because Generation sells power in the wholesale markets, Generation is deemed to be a public utility for purposes of the Federal Power Act and is required to obtain the FERC’s acceptance of the rate schedules for wholesale sales of electricity. In 2000, Generation received authorization from the FERC to sell energy at market-based rates. As is customary with market-based rate schedules, the FERC reserved the right to suspend market-based rate authority on a retroactive basis if it is subsequently determined that Generation or any of its affiliates exercised or have the ability to exercise market power. The FERC is also authorized to order refunds if it finds that market-based rates are unreasonable. Generation recently filed its required triennial review application to continue its market-based rate authorization.

As described above under Energy Delivery - Transmission Services, the FERC issued Order No. 2000 to encourage the voluntary formation of RTOs which would provide transmission service across multiple transmission systems. The intended benefits of establishing these entities includes the development of larger markets and the elimination or reduction of 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 have resulted in delays in development of RTOs. PJM has been approved as an RTO, as has the Midwest ISO. ISO New England, the system operator for New England where Generation also owns facilities, currently has an application pending at the FERC for recognition as an RTO.

The FERC also has fostered a standard market platform for the wholesale markets. The FERC proposals 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 manage congestion on transmission lines, preferably by means of a financially-based system known as locational marginal pricing. The FERC has also issued proposals to encourage FERC-jurisdictional transmission owners to develop RTOs, independent control of the transmission grid and expansion of the transmission grid by providing enhanced returns on equity for transmission assets. The FERC’s plans for standard wholesale markets have met substantial opposition from a number of parties, including some state regulators and other governmental officials that it has been attempting to mitigate with public comment and more flexible proposals. The FERC is likely to move forward with these policies allowing regional variations during the coming year.

FERC Order 2000 has not led to the rapid development of RTOs and the FERC has not yet finalized its standard market proposal, due in part to the resistance noted above. Exelon supports both of these proposals but cannot predict whether they will be successful or if they will ultimately lead to the development of large, successful regional wholesale markets.

The FERC issued a final rule establishing standardized generator interconnection policies and procedures. 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 the FERC should be noted. First, the 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, the 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, the FERC essentially suspended the applicability of this test, holding that no company would be required to undertake any mitigation until after the FERC had held a technical conference on the subject. This technical conference has not been scheduled, but the FERC commissioners have stated publicly that the technical conference will be held in early 2004. In the meantime, Generation recently filed its required triennial review of its market-based rates and argued that the SMA screen should exclude from consideration capacity that is committed under long-term contracts to serve POLR load since it cannot be withheld from the market.

Second, the FERC continues to exhibit a commitment to increased market monitoring with an intent to ensure that high price volatility, such as was seen previously in California, does not occur again. As part of this commitment, the FERC formed a new Office of Market Oversight and Investigation, which reports directly to the FERC Chairman. This new office will assess, among other things, market performance. It is unclear how Generation’s business may be affected 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, which 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 may be sold to another utility and may be placed 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, the FERC might determine that Generation has market power in the MAIN region. If the 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 2003 and estimated for 2004:


	Source of Electric Supply
	2003	2004 (Est.)
Nuclear units (1)	117,502	139,092
Purchases – non-trading portfolio (2)	82,860	31,458
Fossil and hydroelectric units	24,310	21,138

Total supply	224,672	191,688

(1)	Excluding AmerGen in 2003. Approximately 20,346 GWhs are included for AmerGen facilities in 2004 supply.

(2)	Including PPAs with AmerGen.

The fuel costs for nuclear generation are substantially less than fossil-fuel generation. Consequently, nuclear generation is the most cost-effective way for Generation to meet its commitment to supply the requirements of ComEd, PECO and Exelon Energy Company and for sales to other utilities.

The cycle of production and utilization of nuclear fuel includes the mining and milling of uranium ore into uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, the enrichment of the uranium hexafluoride and the fabrication of fuel assemblies. Generation has uranium concentrate inventory and supply contracts sufficient to meet all of its uranium concentrate requirements through 2007. Generation’s contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2007. All of Generation’s enrichment requirements have been contracted through 2007. Contracts for fuel fabrication have been obtained through 2007. Generation does not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment or fabrication services for its nuclear units.

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

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

Substantially all of the natural gas requirements for Boston Generating’s Mystic 8 and Mystic 9 are 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 liquefied natural gas (LNG) import terminal located adjacent to the Mystic station. See Note 13 of Generation’s Notes to Consolidated Financial Statements for information regarding the guarantee to Distrigas.

Natural gas requirements for operating stations 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 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 three years. Generation’s hedge ratio in 2004 for its energy marketing portfolio is approximately 89%. This hedge ratio represents the percentage of forecasted aggregate annual generation supply that is committed to firm sales, including sales to Energy Delivery’s retail load. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand and volatility. During peak periods, the amount hedged declines to assure Generation’s commitment to meet Energy Delivery’s demand, for which the peak demand is during the summer. For the portion of generation supply that is unhedged, fluctuations in market price of energy will cause volatility in Generation’s results of operations.

Power Team also uses financial and commodity contracts for proprietary trading purposes but this activity accounts for a small portion of Power Team’s efforts. In 2003, proprietary trading activities resulted in an $1 million after-tax increase in Generation’s earnings. The trading portfolio is subject to a risk management policy that includes stringent risk management limits including volume, stop-loss and value-at-risk limits to manage exposure to market risk. Additionally, the corporate risk management group and Exelon’s Risk Management Committee (RMC) monitor the financial risks of the power marketing activities. Proprietary trading of derivatives, together with the application of the provisions of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133), may cause volatility in Generation’s future results of operations.

At December 31, 2003, 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 contracts, as expressed in the following tables:


	Net Capacity Purchases (1)		Power Only Sales		Power Only Purchases from Non-Affiliates		Transmission Rights Purchases (2)
2004	$	716	$	3,393	$	1,661	$	113
2005		414		1,088		429		86
2006		410		290		276		3
2007		492		80		253		—
2008		434		—		226		—
Thereafter		3,880		—		723		—

Total	$	6,346	$	4,851	$	3,568	$	202

(1)

Net Capacity Purchases include capacity sales to TXU under the purchase power agreement entered into in connection with the purchase of two generating plants in April 2002, which states that TXU will purchase the plant output from May through September from 2002 through 2006. During the periods covered by the power purchase agreement, TXU is obligated to make fixed capacity payments and to provide fuel to Generation in return for exclusive rights to the energy and capacity of the generation plants. The combined capacity of the two plants is 2,334 MWs. Net capacity purchases also include tolling agreements that are accounted for as operating leases.

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

Additionally, Generation has the following commitments:

Generation has a PPA with ComEd under which Generation has agreed to supply all of ComEd’s load requirements through 2004. Under the ComEd PPA, prices for energy vary depending upon the time of day and month of delivery. An extension of this contract for 2005 and 2006 has been agreed to by ComEd and Generation with substantially the same terms as the PPA currently in effect, except for the prices of energy which were reset to reflect the current rates at the time the extension was agreed to. This extension must still be filed by ComEd with the ICC. Subsequent to 2006, ComEd will obtain all of its supply from market sources, which could include Generation.

Generation has a PPA with PECO under which Generation has agreed to supply PECO with substantially all of PECO’s electric supply needs through 2010. PECO has also assigned its rights and obligations under various PPAs and fuel supply agreements to Generation. Generation supplies power to PECO from the transferred generation assets, assigned PPAs and other market sources.

As part of AmerGen’s acquisition of its Clinton Nuclear Power Station (Clinton), AmerGen entered into a power sales agreement with the seller, IP. The agreement with IP for Clinton is for 69.5% of the output for a term expiring at the end of 2004.

Capital Expenditures

Generation’s business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects. Generation’s estimated capital expenditures for 2004 are as follows:


(in millions)
Production plant	$	573
Nuclear fuel		399

Total	$	972

The majority of Generation’s estimated capital expenditures for 2004 are for nuclear fuel and additions to or upgrades of existing facilities.

Boston Generating

In July 2003, Generation announced that it would transition out of its ownership of Boston Generating, a project subsidiary of Exelon New England, and the related projects and recorded an asset impairment charge of $945 million (before income taxes) associated with its decision. Boston Generating currently owns 3,145 MWs of generating capacity, of which 2,851 MWs are currently available for commercial operations, located in Massachusetts.

The transition out of Generation’s ownership of Boston Generating will take place in a manner that complies with applicable regulatory requirements. For a period of time, Generation expects to continue to provide administrative and operational services to Boston Generating in its operation of the projects. Generation informed the lenders of its decision to exit and that it will not provide additional funding beyond its existing contractual obligations. Generation anticipates that the transition will occur in 2004.

Sithe

On November 25, 2003, Generation, Reservoir and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe. The series of transactions is described below. Immediately prior to these transactions, Sithe was owned 49.9% by Generation, 35.2% by Apollo Energy, LLC (Apollo), and 14.9% by subsidiaries of Marubeni Corporation (Marubeni).

Entities controlled by Reservoir purchased certain Sithe entities holding six U.S. generating facilities, each a qualifying facility under the Public Utility Regulatory Policies Act, in exchange for $37 million ($21 million in cash and a $16 million two-year note); and entities controlled by Marubeni purchased all of Sithe’s entities and facilities outside of North America (other than Sithe Energies Australia (SEA) of which it purchased a 49% interest on November 24, 2003 for separate consideration) for $178 million. Marubeni agreed to acquire the remaining 51% of SEA in 90 days if a buyer is not found, although discussions regarding an extension are ongoing.

Following the sales of the above entities, Generation transferred its wholly owned subsidiary that held the Sithe investment to a newly formed holding company. The subsidiary holding the Sithe investment acquired the remaining Sithe interests from Apollo and Marubeni for $612 million using proceeds from a $580 million bridge financing and available cash. Generation sold a 50% interest in the newly formed holding company for $76 million to an entity controlled by Reservoir. On November 26, 2003, Sithe distributed $580 million of available cash to its parent, which then utilized the distributed funds to repay the bridge financing.

In connection with this transaction, Generation recorded obligations related to $39 million of guarantees in accordance with FASB Interpretation (FIN) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others” (FIN No. 45). These guarantees were issued to protect Reservoir from credit exposure of certain counter-parties through 2015 and other indemnities. In determining the value of the FIN 45 guarantees, Generation utilized a probabilistic model to assess the possibilities of future payments under the indemnifications.

call options vary by acquirer and can extend through March 2006. The pricing of the put and call options is dependent on numerous factors, such as the acquirer, date of acquisition and assets owned by Sithe at the time of exercise. Any closing under either the put or call options is conditioned upon obtaining state and federal regulatory approvals.

Based on Generation’s interpretation of FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN No. 46-R), it is reasonably possible that Generation will consolidate Sithe as of March 31, 2004. See Note 1 of Generation’s Notes to Consolidated Financial Statements for additional information regarding FIN No. 46-R.

Enterprises

Enterprises consists primarily of the energy services business of Exelon Services, the district cooling business of Thermal, the electrical contracting business of F&M Holdings, Inc., a communications joint venture and other investments weighted towards the communications, energy services and retail services industries. In September 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource, Inc. In December 2003, Enterprises signed agreements to sell the Chicago operations and Aladdin facility of Thermal and certain direct investments held by Enterprises. Effective January 1, 2004, Enterprises competitive retail sales business, Exelon Energy Company, became part of Generation.

InfraSource, prior to its sale in September 2003, provided 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 acquired thirteen infrastructure service companies. For the period through the sale in 2003, InfraSource had revenues of approximately $540 million and, at the time of the sale, had approximately 4,000 employees. At December 31, 2003, F&M Holdings, Inc. is primarily the remaining operations of the former InfraSource with approximately 400 employees. Enterprises is continuing to pursue opportunities to sell F&M Holdings, Inc. in 2004.

Exelon Services is engaged in the design, installation and servicing of heating, ventilation and air conditioning facilities for commercial and industrial customers throughout the Midwest. Exelon Services also provides energy-related services, including performance contracting and energy management systems. Enterprises is continuing to pursue opportunities to sell Exelon Services in 2004.

Exelon Energy Company provides retail electric and gas services as an unregulated retail energy supplier in Illinois, Massachusetts, Michigan, New Jersey, Ohio, Pennsylvania and other areas in the Midwest and Northeast United States. Its retail energy sales business is dependent upon continued deregulation of retail electric and gas markets and its ability to obtain supplies of electricity and gas at competitive prices in the wholesale market. The low margin nature of the business makes it important to achieve concentrations of customers with higher volumes so as to manage costs. Exelon Energy Company became part of Generation effective as of January 1, 2004.

Exelon Thermal provides district cooling and related services to offices and other buildings in the central business district of Chicago and in other cities in North America. District cooling involves the production of chilled water at one or more central locations and its circulation to customers’ buildings, primarily for air conditioning. In December 2003, Enterprises signed agreements to sell the Chicago operations and Aladdin thermal facility.

Exelon Communications is the unit of Enterprises through which Exelon manages its communications investments. Exelon Communications’ principal investment is PECO TelCove, formerly known as PECO Adelphia Communications (PECO TelCove). PECO TelCove 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. PECO TelCove is a 50% owned joint venture with Adelphia Business Solutions, doing business as TelCove. PECO TelCove 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.

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, 2003, Exelon Capital Partners had direct investments in ten 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 an immediate exit from all Enterprises’ businesses, but rather businesses may be retained for a period of time if that course of action will increase their value.

Employees

As of January 1, 2004, Exelon and its subsidiaries had approximately 20,000 employees, in the following companies:


ComEd		5,900
PECO		2,300
Generation		7,700
Enterprises		2,200
BSC and Corporate (a)		1,900

Total		20,000

(a)	As a result of The Exelon Way restructuring initiatives to provide greater operational efficiencies, BSC and Corporate includes approximately 400 Energy Delivery shared services employees that provide services to ComEd and PECO.

Approximately 5,800 employees, including 4,100 employees of ComEd, 1,600 employees of Generation and 100 employees of BSC, are covered by collective bargaining agreements (CBAs) with Local 15 of the International Brotherhood of Electrical Workers (IBEW) (IBEW Local 15). AmerGen has separate CBAs for each of its nuclear facilities, which cover an aggregate of approximately 700 employees. The Generation CBA with IBEW Local 15 has been extended to expire on September 30, 2007. The CBA for ComEd and BSC expires on September 30, 2008. The Clinton, Oyster Creek and Three Mile Island (TMI) CBAs expire on December 15, 2005, January 31, 2006 and February 29, 2004, respectively. The CBAs provide for a voluntary severance plan.

In addition to IBEW Local 15 and the three IBEW locals covering the AmerGen facilities, approximately 200 Generation employees are represented by the Utility Workers Union of America. Approximately 1,600 Enterprises employees are represented by unions, including approximately 400 employees who are represented by various local unions of the IBEW. The remaining union employees are members of a number of different local unions, including laborers, welders, operators, plumbers and machinists.

During 2003, an election was held at Exelon Power, a division of Generation, that resulted in union representation. Exelon Power and IBEW Local 614 are currently in negotiations for an initial agreement.

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 for different segments of employees within PECO. In all cases, PECO employees have rejected union representation. On August 15, 2002,

the IBEW filed a petition to conduct a unionization vote of certain of PECO’s employees. On May 21, 2003, the PECO union election was held and a majority of PECO workers voted against union representation. The results of the election have not been certified due to pending challenges and objections. Exelon expects that such petitions, related to segments of employees at PECO, Generation and Enterprises, will continue to be filed in the future.

Environmental Regulation

General

Specific operations of Exelon, primarily those of ComEd, PECO, and Generation, are subject to regulation regarding environmental matters by the United States and by various states and local jurisdictions where Exelon operates its facilities. The Illinois Pollution Control Board (IPCB) has jurisdiction over environmental control in the State of Illinois, together with the Illinois Environmental Protection Agency, which enforces regulations of the IPCB and issues permits in connection with environmental control. The Pennsylvania Department of Environmental Protection (PDEP) has jurisdiction over environmental control in the Commonwealth of Pennsylvania. The Texas Commission on Environmental Quality has jurisdiction in Texas and the Massachusetts Department of Environmental Protection has jurisdiction in Massachusetts. State regulation includes the authority to regulate air, water and noise emissions and solid waste disposals. 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 disposed of low level radioactive wastes resulting from their nuclear generation activities, which are now the responsibility of Generation. A settlement was reached among the Federal and private PRPs, including ComEd and PECO, the Commonwealth of Kentucky (Kentucky) and the EPA concerning their respective roles and responsibilities in conducting remedial activities at the site. Under the settlement, which was incorporated into a Federal court Consent Decree, the private PRPs agreed to perform the initial remedial work at the site and Kentucky agreed to assume responsibility for long-range maintenance and final remediation of the site. On October 5, 2003, the EPA issued a Certificate of Completion indicating that the private PRPs have completed their obligations under the Consent Decree. The site is being turned over to Kentucky as provided in the Consent Decree. The private PRPs, including Generation, will maintain oversight of Kentucky’s activities to assure the stability of the site since the private PRPs have residual liability if there is a remedy failure over the next ten years.

By notice issued in December 1987, the EPA notified several entities, including PECO, that they may be PRPs under CERCLA with respect to wastes resulting from the treatment and disposal of transformers and miscellaneous electrical equipment at a site located in Philadelphia, Pennsylvania (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 the study was approximately 30%. On July 19, 1995, the EPA issued a proposed plan for remediation of the site, which involves removal of contaminated soil, sediment and groundwater and which the EPA estimated would cost approximately $17 million to implement. On June 26, 1998, the EPA issued an order to the non-de minimis PRP group members, and others, including the owner, to implement the remedial design and remedial action.

The PRP group has conducted the remedial design and submitted to the EPA the revised final design on January 15, 2003. During the design process, the PRP group proposed certain revisions to the EPA’s preferred remedy, in response to which the EPA has issued two explanations of significant differences that are expected to reduce the costs of the preferred remedy. The final design estimates for the cost to implement the remedial action range from $12 million to $15 million. At this time, PECO 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 PECO. The ultimate cost to the PRPs and to PECO 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 42 former MGP sites for which it may be liable for remediation. Of these 42 sites, the Illinois Protection Agency has approved the clean-up of three sites. Similarly, PECO has identified 27 sites where former MGP activities may have resulted in site contamination. Of these 27 sites, the Pennsylvania Department of Environmental Protection has approved the clean-up of six sites. With respect to these sites, ComEd and PECO are presently engaged in performing various levels of activities, including initial evaluation to determine the existence and nature of the contamination, detailed evaluation to determine the extent of the contamination and the necessity and possible methods of remediation, and implementation of remediation. ComEd and PECO are working closely with regulatory authorities in the various jurisdictions to develop and implement appropriate plans and schedules for evaluation, risk ranking, detailed study and remediation activities on an individual site and overall program basis. The status of each of the sites in the program varies and is

reviewed periodically with the regulatory authorities. At December 31, 2003, ComEd and PECO had accrued $64 million (discounted) and $41 million (discounted), respectively, for investigation and remediation of these MGP sites that currently can be reasonably estimated. ComEd’s reserve was increased by $17 million during 2002 and an additional $12 million during 2003 in connection with the ongoing remediation for a MGP site in Oak Park, Illinois. The remediation of the Oak Park site was substantially complete as of December 31, 2003. However, there are several personal injury and property damage claims pending related to this site. ComEd and PECO believe that they could incur additional liabilities with respect to MGP sites, which cannot be reasonably estimated at this time. PECO has sued, and ComEd is in negotiations, with a number of insurance carriers seeking indemnity/coverage for remediation costs associated with these former MGP sites. Additionally, PECO is currently collecting through regulated gas rates, revenues to offset expenditures on MGP site remediation.

Air

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

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

Generation has completed implementation of measures, including the installation of NO_x emissions controls and the imposition of certain operational constraints, to comply with the Reasonably Available Control Technology limitations and state-level ozone season (May to September) NO_x reduction regulations. These state-level regulations were developed by eastern states to reduce summertime NO_x emissions pursuant to several Federal NO_x reduction regulations adopted by the Federal EPA during 1998 and 1999 to address regional “ozone transport.” State level NO_x reduction regulations took effect May 1, 2003 in Pennsylvania and Massachusetts. Compliance in Illinois is required starting May 31, 2004. Texas is not covered by the EPA’s ozone transport regulations. When fully implemented on May 31, 2004, the EPA’s ozone transport regulations will require 19 eastern states to reduce summertime NO_x emissions.

Exelon has evaluated options for compliance with the new NO_x regulations and installed controls on the two coal-fired units at the Eddystone Generating Station (Selective Non-Catalytic Reduction) and installed controls on the two coal-fired units (Selective Catalytic Reduction) at the Keystone Generating Station. 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 management of low sulfur fuels on unit 7, and dry low NO_x combustors, Selective Catalytic Reduction and CO Oxidation Catalyst on the new gas-fired units 8 and 9 that achieved commercial operation in 2003. Generation’s NO_x compliance program will be supplemented with the purchase of additional NO_x allowances on an as-needed basis. The eight new peaking units commissioned during 2002 at the Southeast Chicago Generating Station are equipped with NO_x controls that meet requirements for new sources. The Exelon generating stations in the Dallas/Fort Worth (DFW) area are required to comply with the DFW NO_x State Implementation Plan (SIP) that commenced on May 1, 2003, with full implementation on May 1, 2005. Additionally, beginning May 1, 2003 these plants must comply with the Emission Banking and Trading of Allowances (EBTA) program established by the enactment of Senate Bill 7 during the 76th Texas Legislative session for the purpose of achieving substantial reductions in NO_x from grandfathered electric generating facilities. To comply with both the DFW NO_x SIP and EBTA program, Generation has embarked on a plan to install NO_x control equipment on several of the units at the Handley and Mountain Creek generating stations.

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

Several other legislative and regulatory proposals regarding the control of emissions of air pollutants from a variety of sources, including generating plants, are under active consideration. On the Federal legislative front, several multi-pollutant bills have been introduced in Congress that would reduce generating plant emissions of NO_x, SO₂, mercury and/or carbon dioxide starting late this decade. On the Federal regulatory front, the EPA announced in December 2003 its intention to publish several proposed regulations in the Federal Register during early 2004. One proposed regulation would require a reduction in mercury emissions from coal-fired plants, and establish nickel emission standards for oil-fired plants later this decade. Another proposed regulation, “Interstate Air Quality Rule,” would require further reductions of NO_x and SO₂ emissions in the eastern United States in two phases (2010 and 2015) to support regional attainment of the new federal NAAQS for fine particulate (PM2.5) and ground level ozone (8-hour standard). Exelon is unable at this time to ascertain which proposals may take effect, what requirements they may contain, or how they may affect Exelon’s businesses. At this time, Exelon can provide no assurance that these proposals if adopted will not have a significant effect on Exelon’s operations and costs.

Costs

At December 31, 2003, ComEd, PECO and Generation accrued $69 million, $50 million and $10 million, respectively, for various environmental investigation and remediation. These costs include approximately $64 million at ComEd and $41 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 2004 at ComEd, PECO and Generation for compliance with environmental requirements total approximately $10 million, $9 million and $3 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

Effective December 31, 2003, ComEd Funding LLC, ComEd Transitional Funding Trust, ComEd Financing II, ComEd Financing III, PECO Energy Transition Trust, and PECO Energy Capital Trust III were deconsolidated from the financial statements of Exelon, ComEd, and PECO in accordance with FIN No. 46-R. Effective July 1, 2003, PECO Energy Capital Trust IV, a financing subsidiary created in May 2003, was deconsolidated from the financial statements of Exelon and PECO in accordance with FIN No. 46, prior to its subsequent revision in December 2003. Amounts owed to these financing trusts were recorded as long-term debt to affiliates, long-term debt to ComEd Transitional Funding Trust and long-term debt to PECO Energy Transitional Trust debt to PECO Energy Transitional Trust within the Consolidated Balance Sheets, and interest owed to these entities subsequent to the adoption of FIN No. 46 and FIN No. 46-R was recorded as interest expense to affiliates within the Consolidated Statements of Income. Prior periods were not restated.

ComEd Transitional Funding Trust (ComEd Funding Trust), a Delaware statutory trust, was formed on October 28, 1998, pursuant to a trust agreement among First Union Trust Company, National Association, now Wachovia Bank, National Association, as Delaware trustee, and two individual trustees appointed by ComEd. ComEd Funding Trust was created for the sole purpose of issuing transitional funding notes to securitize

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

ComEd Financing I, a Delaware statutory 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, carried an annual distribution rate of 8.48% and were mandatorily redeemable on September 30, 2035. The sole assets of ComEd Financing I were $206 million principal amount of 8.48% subordinated deferrable interest notes due September 30, 2035, issued by ComEd. On March 20, 2003, ComEd Financing I redeemed all of its trust preferred securities at a redemption price of 100% of the liquidation amount, plus accrued distributions to the redemption date. ComEd redeemed $206 million of its 8.48% subordinated debentures issued to ComEd Financing I. The preferred securities were refinanced with trust preferred securities (see ComEd Financing III below).

ComEd Financing II, a Delaware statutory trust, was formed by ComEd on November 20, 1996. ComEd Financing II was created solely for the purpose of issuing $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 $155 million principal amount of 8.50% subordinated deferrable interest debentures due January 15, 2027, issued by ComEd.

ComEd Financing III, a Delaware statutory trust, was formed by ComEd on September 5, 2002. ComEd Financing III was created for the sole purpose of issuing and selling preferred and common securities. On March 17, 2003, ComEd Financing III issued $200 million of trust preferred securities, carrying an annual distribution rate of 6.35%, which are mandatorily redeemable on March 15, 2033. The sole assets of ComEd Financing III are $206 million principal amount of 6.35% subordinated deferrable interest debentures due March 15, 2033, issued by ComEd. The preferred securities were used to refinance the preferred securities of ComEd Financing I.

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

PECO Energy Capital Corp., a wholly owned subsidiary of PECO, 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 deferrable interest 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, 2003, the Partnership held $78 million aggregate principal amount of the Subordinated Debentures.

PECO Energy Capital Trust II (Trust II) was created in June 1997 as a Delaware statutory trust solely for the purpose of issuing $50 million 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. In June 2003, Trust II redeemed all of its 8% trust preferred securities at a redemption price of $25 per trust receipt, plus accrued and unpaid distributions. The preferred securities were refinanced with trust preferred securities (see Trust IV below).

PECO Energy Capital Trust III (Trust III) was created in April 1998 as a Delaware statutory trust solely for the purpose of issuing $78 million 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, 2003, Trust III had outstanding 78,105 Trust III Receipts. At December 31, 2003, the assets of Trust III consisted solely of 78,105 Series D Preferred Securities with an aggregate stated liquidation preference of $78 million.

PECO Energy Capital Trust IV (Trust IV) was created in May 2003 as a Delaware statutory trust solely for the purpose of issuing $100 million trust preferred securities and common securities and purchasing the 5.75% deferrable interest subordinated debentures. PECO is the sole owner of all of the common securities of the Trust IV. The sole assets of Trust IV are $100 million principal amount of 5.75% subordinated debentures issued by PECO.

Executive Officers of the Registrants at December 31, 2003

Exelon


Name	Age	Position
Rowe, John W.	58	Chairman and Chief Executive Officer
Kingsley Jr., Oliver D.	61	President and Chief Operating Officer
McLean, Ian P.	54	Executive Vice President
Mehrberg, Randall E.	48	Executive Vice President and General Counsel
Moler, Elizabeth A.	54	Executive Vice President
Shapard, Robert S.	48	Executive Vice President and Chief Financial Officer
Strobel, Pamela B.	51	Executive Vice President and Chief Administrative Officer
Bemis, Michael B.	56	Senior Vice President
Snodgrass, S. Gary	52	Senior Vice President and Chief Human Resources Officer
Hilzinger, Matthew F.	40	Vice President and Corporate Controller

ComEd


Name	Age	Position
Rowe, John W.	58	Chairman and Chief Executive Officer, Exelon, and Chair and Director
Kingsley Jr., Oliver D.	61	President and Chief Operating Officer, Exelon, and Director
Shapard, Robert S.	48	Executive Vice President and Chief Financial Officer, Exelon, and Director
Snodgrass, S. Gary	52	Senior Vice President and Chief Human Resources Officer, Exelon, and Director
Bemis, Michael B.	56	President, Exelon Energy Delivery, and Director
Clark, Frank M.	58	President and Director
Mitchell, J. Barry	55	Senior Vice President, Treasurer and Chief Financial Officer
DesParte, Duane M.	40	Vice President and Controller

PECO


Name	Age	Position
Rowe, John W.	58	Chairman and Chief Executive Officer, Exelon, and Director
Kingsley Jr., Oliver D.	61	President, Exelon, and Director
Shapard, Robert S.	48	Executive Vice President and Chief Financial Officer, Exelon, and Director
Bemis, Michael B.	56	President, Exelon Energy Delivery, and Director
O’Brien, Denis P.	43	President and Director
Mitchell, J. Barry	55	Senior Vice President, Treasurer and Chief Financial Officer
DesParte, Duane M.	40	Vice President and Controller

Generation


Name	Age	Position
Rowe, John W.	58	Chairman and Chief Executive Officer, Exelon
Kingsley Jr., Oliver D.	61	President, Exelon, and Chief Executive Officer and President
Shapard, Robert S.	48	Executive Vice President and Chief Financial Officer, Exelon
McLean, Ian P.	54	Executive Vice President, Exelon, and President, Power Team
Mitchell, J. Barry	55	Senior Vice President, Treasurer and Chief Financial Officer
Skolds, John L.	53	Senior Vice President, Exelon, and President, Exelon Nuclear
Young, John F.	47	Senior Vice President, Exelon, and President, Exelon Power
Hilzinger, Matthew F.	40	Vice President and Corporate Controller, Exelon

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 3, 2001, Matthew F. Hilzinger, who was elected effective April 15, 2002, Robert S. Shapard, who was elected effective October 21, 2002, Michael B. Bemis, who was elected effective August 12, 2002, John F. Young, who was elected effective March 3, 2003, and Duane M. DesParte, who was elected effective February 17, 2003.

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

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

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

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

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

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

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

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

Prior to his election to his listed position, Mr. Bemis was Chief Executive Officer of Entergy’s London Electricity PLC; and Chairman and CEO of Master Graphics, Inc.

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

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. 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 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. DesParte was Partner at Deloitte & Touche LLP; and Partner at Arthur Andersen LLP.

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

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. Young was Senior Vice President of Sierra Pacific Resources Corporation; President of Avalon Consulting; and Executive Vice President of Southern Generation.

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 at December 31, 2003 were as follows:


	Voltage (Volts)	Circuit Miles
*ComEd*	765,000 345,000 138,000	90 2,580 2,808

*PECO*	500,000 220,000 132,000 66,000	297 499 229 167

ComEd’s electric distribution system includes 43,400 circuit miles of overhead lines and 31,700 circuit miles of underground lines. PECO’s electric distribution system includes 12,900 circuit miles of overhead lines and 8,327 circuit miles of underground lines.

Gas

The following table sets forth PECO’s gas pipeline miles at December 31, 2003:


		Pipeline Miles
Transmission		31
Distribution		6,363
Service piping		5,250

Total		11,644

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

Mortgages

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

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

Insurance

ComEd and PECO maintain property insurance against loss or damage to Energy Delivery’s properties by fire or other perils, subject to certain exceptions. ComEd and PECO are self-insured to the extent that any losses may exceed the amount of insurance maintained. Any such losses could have a material adverse effect on the consolidated financial condition or results of operations of ComEd or PECO.

Generation

The following table sets forth Generation’s owned net electric generating capacity by station at December 31, 2003:

Station

Location

No. of
Units

Percent
Owned (1)

Primary

Fuel Type

Dispatch

Type

Net Generation
Capacity(MW) (2)

Nuclear⁽³⁾

Braidwood

Braidwood, IL

Uranium

Base-load

2,388

Byron

Byron, IL

Uranium

Base-load

2,364

Clinton

Clinton, IL

Uranium

Base-load

1,030

Dresden

Morris, IL

Uranium

Base-load

1,742

LaSalle County

Seneca, IL

Uranium

Base-load

2,288

Limerick

Limerick Twp., PA

Uranium

Base-load

2,309

Oyster Creek

Forked River, NJ

Uranium

Base-load

625

Peach Bottom

Peach Bottom Twp., PA

50.00

Uranium

Base-load

1,131

(4)

Quad Cities

Cordova, IL

75.00

Uranium

Base-load

1,303

(4)

Salem

Hancock’s Bridge, NJ

42.59

Uranium

Base-load

942

(4)

Three Mile Island

Londonderry Twp., PA

Uranium

Base-load

837

16,959

Fossil (Steam Turbines)

Conemaugh

New Florence, PA

20.72

Coal

Base-load

352

(4)

Cromby 1

Phoenixville, PA

Coal

Base-load

144

Cromby 2

Phoenixville, PA

Oil/Gas

Intermediate

201

Delaware

Philadelphia, PA

Oil

Peaking

250

Eddystone 1, 2

Eddystone, PA

Coal

Base-load

581

Eddystone 3, 4

Eddystone, PA

Oil/Gas

Intermediate

760

Fairless Hills

Falls Twp., PA

Landfill Gas

Peaking

Fore River

Weymouth, MA

Gas

Intermediate

688

Handley 1,2,4,5

Fort Worth, TX

Gas

Peaking

1,041

Handley 3

Fort Worth, TX

Gas

Intermediate

400

Keystone

Shelocta, PA

20.99

Coal

Base-load

358

(4)

Mountain Creek 2, 3, 6, 7

Dallas, TX

Gas

Peaking

343

Mountain Creek 8

Dallas, TX

Gas

Intermediate

550

Mystic 7

Everett, MA

Oil/Gas

Intermediate

555

(5)

Mystic 8, 9

Everett, MA

Gas

Intermediate

1,600

New Boston 1

South Boston, MA

Gas

Intermediate

353

Schuylkill

Philadelphia, PA

Oil

Peaking

166

Wyman

Yarmouth, ME

5.89

Oil

Intermediate

(4)

8,438

(continued on next page)

Station

Location

No. of
Units

Percent
Owned (1)

Primary

Fuel Type

Dispatch

Type

Net Generation
Capacity(MW) (2)

Fossil (Combustion Turbines)

Chester

Chester, PA

Oil

Peaking

Croydon

Bristol Twp., PA

Oil

Peaking

384

Delaware

Philadelphia, PA

Oil

Peaking

Eddystone

Eddystone, PA

Oil

Peaking

Falls

Falls Twp., PA

Oil

Peaking

Framingham

Framingham, MA

Oil

Peaking

LaPorte

LaPorte, TX

Gas

Peaking

160

Medway

West Medway, MA

Oil

Peaking

110

Moser

Lower Pottsgrove Twp., PA

Oil

Peaking

Mystic

Everett, MA

Oil

Peaking

New Boston

South Boston, MA

Gas

Peaking

Pennsbury

Falls Twp., PA

Landfill Gas

Peaking

Richmond

Philadelphia, PA

Oil

Peaking

Salem

Hancock’s Bridge, NJ

42.59

Oil

Peaking

(4)

Schuylkill

Philadelphia, PA

Oil

Peaking

South East Chicago

Chicago, IL

Gas

Peaking

312

Southwark

Philadelphia, PA

Oil

Peaking

1,474

Fossil (Internal Combustion/Diesel)

Conemaugh

New Florence, PA

20.72

Oil

Peaking

(4)

Cromby

Phoenixville, PA

Oil

Peaking

Delaware

Philadelphia, PA

Oil

Peaking

Keystone

Shelocta, PA

20.99

Oil

Peaking

(4)

Schuylkill

Philadelphia, PA

Oil

Peaking

Hydroelectric

Conowingo

Harford Co., MD

Hydroelectric

Base-load

536

Muddy Run

Lancaster Co., PA

Hydroelectric

Intermediate

1,072

1,608

Total

136

28,492

(1)	100%, unless otherwise indicated.

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

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

(4)	Net generation capacity is stated at proportionate ownership share.

(5)	In December 2003, the ISO New England granted permission for Exelon New England to cease operations at Mystic 4, 5, 6.

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 and fossil and hydroelectric business interruption 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

ComEd

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 and for breach of contract. On November 25, 2002, the court granted the developers’ motions for summary judgment. The judge also entered a permanent injunction enjoining ComEd from refusing to pay the retail rate on the grounds of the amendment, and Illinois from denying ComEd a tax credit on account of such purchases. 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. While ComEd cannot currently predict the outcome of this action, ComEd does not believe that it will have a material adverse impact on ComEd’s results of operations.

PECO and Generation

Real Estate Tax Appeals. PECO and Generation are each challenging real estate taxes assessed on nuclear plants since 1997. PECO is involved in litigation in which it is contesting taxes assessed in 1997 under the Pennsylvania Public Utility Realty Tax Act of March 4, 1971, as amended (PURTA) and has appealed local real estate assessments for 1998 and 1999 on the Limerick Generating Station (Montgomery County, PA) (Limerick) and Peach Bottom Atomic Power Station (York County, PA) (Peach Bottom) plants. Generation is involved in real estate tax appeals for 2000 through 2003, also regarding the valuation of its Limerick and Peach Bottom plants, its Quad Cities Station (Rock Island County, IL) and, through AmerGen, TMI (Dauphin County, PA).

During the third quarter of 2003, upon completion of updated nuclear plant appraisal studies, PECO and Generation recorded reductions of $58 million and $15 million, respectively, to reserves recorded for exposures associated with the real estate taxes. While PECO and Generation believe the resulting reserve balances as of December 31, 2003 reflect the most likely probable expected outcome of the litigation and appeals proceedings in accordance with SFAS No. 5, “Accounting for Contingencies,” the ultimate outcome of such matters could result in additional unfavorable or favorable adjustments to the consolidated financial statements of PECO or Generation, and such adjustments could be material.

Generation

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. Several of these actions resulted in nominal jury verdicts or were settled or dismissed. One action resulted in an award for the plaintiffs for a more substantial amount, but was reversed on April 22, 2003 by the Tenth Circuit Court of Appeals and remanded for retrial. An appeal by the plaintiffs to the United States Supreme Court was denied on November 10, 2003. No date has been set for a new trial.

On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for any liability incurred by Cotter as a result of these actions, as well as any liability arising

in connection with the West Lake Landfill discussed in the next paragraph. In connection with Exelon’s 2001 corporate restructuring, the responsibility to indemnify Cotter for any liability related to these matters was transferred by ComEd to Generation. Generation cannot predict the ultimate outcome of the cases.

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 and three other companies identified by the EPA as PRPs have 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, and, as such, no amounts have been accrued as of December 31, 2003.

Raytheon and Mitsubishi Litigation. In May 2002, Raytheon Corporation (Raytheon) filed an arbitration against Sithe Fore River Development, LLC (now Fore River Development, LLC) in the International Chamber of Commerce Court of Arbitration (Arbitration Court). Raytheon is seeking equitable relief and damages totaling over $45 million for alleged owner-caused performance delays and force majeure events 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, governed the design, engineering, construction, start-up, testing and delivery of an 800-MW combined-cycle power plant in Weymouth, Massachusetts. Hearings by the Arbitration Court with respect to liability were held in January and February 2003. On May 12, 2003, the Arbitration Court issued an interim order finding in favor of Raytheon on liability, but limited the grounds upon which Raytheon could claim schedule and cost relief. The Arbitration Court ordered the parties to proceed to a damages phase to determine what, if any, damages Raytheon may recover. Hearings by the Arbitration Court with respect to damages were conducted in June and July 2003 and a final decision is expected in the first quarter of 2004.

In a related proceeding, on October 2, 2003, Mitsubishi Heavy Industries, LTD (MHI) and Mitsubishi Heavy Industries of America (MHIA) filed an action in the New York Supreme Court against Fore River Development, LLC and Mystic Development, LLC (collectively, the Project Companies) seeking to enjoin these indirect subsidiaries of Generation from drawing upon letters of credit posted to guarantee MHI’s performance under certain gas turbine contracts. MHI and MHIA also is seeking $34 million from these entities in connection with work performed on these contracts. The Project Companies filed a third-party complaint against Raytheon, claiming that Raytheon was responsible for the MHI and MHIA contracts.

On August 29, 2003, Raytheon filed an action against the Project Companies and BNP Paribas in the Massachusetts Superior Court (Superior Court) alleging that the Project Companies and BNP Paribas had failed to provide adequate assurance that Raytheon would be paid the remaining amounts due under the Fore River and Mystic EPC contracts. Raytheon is seeking: (1) an injunction preventing the Project Companies and BNP Paribas from drawing upon certain letters of credit guaranteeing Raytheon’s performance; (2) the right to terminate the construction contracts; and (3) an order allowing Raytheon to seize project funds totaling approximately $40 million. Raytheon subsequently dismissed BNP Paribas from the litigation. On November 25, 2003, the Massachusetts Superior Court dismissed Raytheon’s claims in Massachusetts holding that Raytheon’s claims should have been brought in the New York Supreme Court proceeding. As a result of this decision, all of the litigation was transferred and consolidated into the New York Supreme Court action and all parties have moved for summary judgment. The court has not yet issued any decision.

Clean Air Act.On June 1, 2001, the EPA issued to a subsidiary of the Company a Notice of Violation (NOV) and Reporting Requirement pursuant to Sections 113 and 114 of the Clean Air Act. The NOV alleges numerous exceedances of opacity limits and violations of opacity-related monitoring, recording and reporting requirements at Mystic Station in Everett, Massachusetts. On January 8, 2002, the EPA indicated that it had decided to resolve the NOV through an administrative compliance order and a judicial civil penalty action. In

March 2002, the EPA issued and Mystic I, LLC, doing business as Mystic Generating (formerly known as Exelon Mystic Generating, LLC) (Mystic), a wholly owned subsidiary of the Company, voluntarily entered a Compliance Order and Reporting Requirement (Order) regarding Mystic Station. Under the Order, Mystic Station installed new ignition equipment on three of the four units at the plant. Mystic Station also undertook an extensive opacity monitoring and testing program for all four units at the plant to help determine if additional compliance measures are needed. Pursuant to the requirements of the Order, the subsidiary switched three of the four units to a lower sulfur fuel oil by September 1, 2002. The Order did not address civil penalties. By letter dated April 21, 2003, the United States Department of Justice notified the subsidiary that, at the request of the EPA, it intended to bring a civil penalty action, but also offered the opportunity to resolve the matter through settlement discussions. Mystic has entered into a consent decree with the EPA and the Department of Justice, the net discounted cost of which is approximately $4 million. The consent decree is subject to the approval of the United States District Court of the District of Massachusetts.

General

Exelon, ComEd, PECO and Generation are involved in various other litigation matters that are being defended and handled in the ordinary course of business, and Exelon, ComEd, PECO and Generation maintain accruals for such costs that are probable of being incurred and subject to reasonable estimation. The ultimate outcome of such matters, as well as the matters discussed above, while uncertain, is 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, PECO and Generation

None.

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Exelon

The information required by this Item with respect to market information relating to Exelon’s common stock is incorporated herein by reference to “Market for Registrant’s Common Equity and Related Stockholder Matters” in Exhibit 99-2 to Exelon’s Current Report on Form 8-K dated February 20, 2004.

ComEd

As of February 1, 2004, there were outstanding 127,016,494 shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were held by Exelon. At February 1, 2004, in addition to Exelon, there were approximately 278 holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.

PECO

As of February 1, 2004, there were outstanding 170,478,507 shares of common stock, without par value, of PECO, all of which were held by Exelon.

Generation

As of February 1, 2004, Exelon held 100% of the member interest in Generation.

Exelon, ComEd, PECO and Generation

Dividends

Under applicable federal law, Exelon, ComEd, PECO and Generation can pay dividends only from retained, undistributed or current earnings. Under Illinois law, ComEd may not pay any dividend on its stock unless “[its] earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. At December 31, 2003, Exelon had retained earnings of $2.3 billion, which includes ComEd’s retained earnings of $883 million (of which $709 million had been appropriated for future dividends), PECO’s retained earnings of $546 million and Generation’s undistributed earnings of $602 million.

The following table sets forth Exelon’s quarterly cash dividends paid during 2003 and 2002:


	2003								2002
(per share)	4^th Quarter		3^rd Quarter		2^nd Quarter		1^st Quarter		4^th Quarter		3^rd Quarter		2^nd Quarter		1^st Quarter
Exelon	$	0.50	$	0.50	$	0.46	$	0.46	$	0.44	$	0.44	$	0.44	$	0.44

The following table sets forth ComEd’s and PECO’s quarterly common dividend payments and Generation’s quarterly distributions:


	2003								2002
(in millions)	4^th Quarter		3^rd Quarter		2^nd Quarter		1^st Quarter		4^th Quarter		3^rd Quarter		2^nd Quarter		1^st Quarter
ComEd	$	95	$	95	$	90	$	121	$	117	$	118	$	117	$	118
PECO		79		79		75		90		85		85		85		85
Generation		73		71		45		—		—		—		—		—

On January 27, 2004, the Exelon Board of Directors declared a quarterly dividend of $0.55 per share on Exelon’s common stock. The January 2004 declaration equates to an annual dividend rate of $2.20 per share. Payment of future dividends is subject to approval and declaration by the Board.

On January 27, 2004, the Exelon Board of Directors approved a 2-for-1 stock split of Exelon’s common stock, effective upon receipt of all necessary regulatory approvals and the filing of an amendment to Exelon’s articles of incorporation. The share and per-share amounts in this Form 10-K do not reflect the stock split.

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 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). As of December 31, 2003, ComEd had appropriated $709 million of retained earnings for future dividend payments.

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, 2003, such capital was $2.5 billion and amounted to about 29 times the liquidating value of the outstanding preferred stock of $87 million.

PECO 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 debentures which were issued to the Partnership or Trust IV; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of Trust IV or the 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 20, 2004.

ComEd

The selected consolidated financial data presented below has been derived from the audited consolidated 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 in Item 7 herein.

ComEd was the principal subsidiary of Unicom Corporation (Unicom) prior to the merger with Exelon (Merger) on October 20, 2000 (Merger Date). The Merger was accounted for using the purchase method of accounting in accordance with accounting principles generally accepted in the United States (GAAP). The effects of the purchase method were reflected in the consolidated financial statements of ComEd as of the Merger Date. Accordingly, ComEd’s consolidated financial statements presented for the period after the Merger reflect a new basis of accounting.

The information for the year ended 2000 is presented for the periods before and after the Merger.


	For the Years Ended December 31,						Oct. 20 - Dec. 31 2000		Jan. 1 - Oct. 19 2000		For the Year Ended December 31, 1999
(in millions)	2003		2002		2001		Oct. 20 - Dec. 31 2000		Jan. 1 - Oct. 19 2000		For the Year Ended December 31, 1999
Statement of Income data:
Operating revenues	$	5,814	$	6,124	$	6,206	$	1,310	$	5,702	$	6,793
Operating income		1,567		1,766		1,594		338		1,048		1,549
Income before cumulative effect of changes in accounting principles		702		790		607		133		599		623
Cumulative effect of a change in accounting principle (net of income taxes)		5		—		—		—		—		—

Net income	$	707	$	790	$	607	$	133	$	599	$	623

Net income on common stock	$	707	$	790	$	607	$	133	$	596	$	599


	December 31,
(in millions)	2003		2002		2001		2000		1999
Balance Sheet data:
Current assets	$	1,313	$	1,049	$	1,025	$	2,172	$	4,045
Property, plant and equipment, net		9,096		8,689		8,243		8,499		12,795
Goodwill, net		4,719		4,916		4,902		4,766		—
Regulatory assets, net		—		—		—		268		524
Other deferred debits and other assets		2,823		1,662		1,682		4,493		5,212

Total assets	$	17,951	$	16,316	$	15,852	$	20,198	$	22,576

Current liabilities	$	1,557	$	2,023	$	1,797	$	1,723	$	3,427
Long-term debt, including long-term debt to financing trusts (1)		5,887		5,268		5,850		6,882		6,962
Regulatory liabilities		1,891		486		225		—		—
Other deferred credits and other liabilities		2,274		2,451		2,568		5,082		6,456
Mandatorily redeemable preference stock		—		—		—		—		69
Mandatorily redeemable preferred securities of subsidiary trusts (1)		—		330		329		328		350
Shareholders’ equity		6,342		5,758		5,083		6,183		5,312

Total liabilities and shareholders’ equity	$	17,951	$	16,316	$	15,852	$	20,198	$	22,576

(1)	Upon adoption of FIN No. 46-R in 2003, the mandatorily redeemable preferred securities were reclassified as long-term debt to affiliates as of December 31, 2003.

PECO

The selected consolidated financial data presented below has been derived from the audited consolidated 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 in Item 7 herein.


	For the Years Ended December 31,
(in millions)	2003		2002		2001		2000		1999
Statement of Income data:
Operating revenues	$	4,388	$	4,333	$	3,965	$	5,950	$	5,478
Operating income		1,056		1,093		999		1,222		1,373
Income before cumulative effect of a change in accounting principle		473		486		425		483		582
Cumulative effect of a change in accounting principle (net of income taxes)		—		—		—		24		—

Net income	$	473	$	486	$	425	$	507	$	582

Net income on common stock	$	468	$	478	$	415	$	497	$	570


	December 31,
(in millions)	2003		2002		2001		2000		1999
Balance Sheet data:
Current assets	$	632	$	927	$	813	$	1,779	$	1,221
Property, plant and equipment, net		4,256		4,159		4,039		5,138		4,982
Noncurrent regulatory assets		5,226		5,546		5,774		6,046		6,094
Other deferred debits and other assets		232		88		112		1,813		790

Total assets	$	10,346	$	10,720	$	10,738	$	14,776	$	13,087

Current liabilities	$	742	$	1,538	$	1,335	$	2,974	$	1,286
Long-term debt, including long-term debt to financing trusts (1)		5,239		4,951		5,438		6,002		5,969
Deferred credits and other liabilities		3,349		3,342		3,358		3,860		3,738
Mandatorily redeemable preferred securities of subsidiary trusts (1)		—		128		128		128		128
Mandatorily redeemable preferred stock		—		—		19		37		56
Shareholders’ equity		1,016		761		460		1,775		1,910

Total liabilities and shareholders’ equity	$	10,346	$	10,720	$	10,738	$	14,776	$	13,087

(1)	Upon adoption of FIN No. 46-R in 2003, the mandatorily redeemable preferred securities were reclassified as long-term debt to affiliates as of December 31, 2003.

Generation

The selected consolidated financial data presented below has been derived from the audited consolidated 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 in Item 7 herein.


	For the Years Ended December 31,
(in millions)	2003			2002		2001		2000		1999
Statement of Income data:
Operating revenues	$	8,135		$	6,858	$	6,826	$	3,274	$	2,425
Operating income (loss)		(194	)		509		872		441		300
Income (loss) before cumulative effect of changes in accounting principles		(241	)		387		512		260		204
Cumulative effect of changes in accounting principles (net of income taxes)		108			13		12		—		—

Net income (loss)	$	(133	)	$	400	$	524	$	260	$	204


	December 31,
(in millions)	2003		2002		2001		2000		1999
Balance Sheet data:
Current assets	$	2,553	$	1,805	$	1,435	$	1,793	$	395
Property, plant and equipment, net		7,106		4,698		2,003		1,727		990
Deferred debits and other assets		5,105		4,402		4,700		4,742		907

Total assets	$	14,764	$	10,905	$	8,138	$	8,262	$	2,292

Current liabilities	$	3,564	$	2,594	$	1,097	$	2,176	$	404
Long-term debt		1,649		2,132		1,021		205		209
Deferred credits and other liabilities		6,592		3,226		3,212		3,271		729
Minority interest		3		54		—		—		—
Members’ equity		2,956		2,899		2,808		2,610		950

Total liabilities and members’ equity	$	14,764	$	10,905	$	8,138	$	8,262	$	2,292

The consolidated financial statements of Generation as of December 31, 2000 and for the year then ended present the financial position, results of operations and net cash flows of the generation-related business of Exelon prior to its corporate restructuring on January 1, 2001. Generation operated as a separate business subsequent to electric-industry restructuring in Pennsylvania effective January 1, 1999.

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 20, 2004.

ComEd, PECO and Generation

The Critical Accounting Policies and Estimates and New Accounting Pronouncement sections presented below indicate the registrant or registrants to which each policy, estimate or accounting standard is applicable. “We” or “Our” as utilized in the Critical Accounting Policies and Estimates and New Accounting Pronouncements sections is defined as the registrant or registrants identified in each subheading.

Critical Accounting Policies and 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 policies, estimates and assumptions with its Accounting and Disclosure Governance Committee on a regular basis and provides periodic updates on management decisions to the Audit Committee of the Exelon Board of Directors. Management believes that the following areas require significant management judgment regarding the application of an accounting policy or in making estimates and assumptions to account for matters that are inherently uncertain and that may change in subsequent periods: accounting for derivative instruments, regulatory assets and liabilities, nuclear decommissioning, depreciable lives of property, plant and equipment, asset impairments including goodwill, severance accounting, defined benefit pension and other postretirement welfare benefits, taxation, unbilled energy revenues and environmental costs. Further discussion of the application of these accounting policies can be found in the Notes to Consolidated Financial Statements.

Accounting for Derivative Instruments (ComEd, PECO and Generation)

We generally account for derivative financial instruments on our balance sheet at their fair value unless they qualify for a normal purchases and normal sales exception or unless specific hedge accounting criteria are met. How such instruments are classified affects how they are reported in our financial statements. If the normal purchases and normal sales exception applies, then gains and losses are recognized when the underlying physical transaction affects earnings. If the derivative qualifies as a cash-flow hedge, changes in the fair value of the derivative are recorded in other comprehensive income in shareholders’ equity. If neither applies, then changes in the fair value of the derivative are recognized in our earnings.

The availability of the normal purchases and normal sales exception is based upon our assessment of the ability and intent to deliver or take delivery, which 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 these contracts not qualifying for the normal purchases and normal sales exception.

Identification of an energy contract as a qualifying cash-flow hedge requires us to determine that the contract is in accordance with our Risk Management Policy, the forecasted future transaction is probable, and 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 such an energy contract designated as a hedge. We reassess these cash-flow hedges on a regular basis to determine if they continue to be effective and that the forecasted future transactions are 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.

As a part of our accounting for derivatives, 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 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 is a widely accepted valuation methodology.

Regulatory Assets and Liabilities (ComEd and PECO)

We account for our regulated electric and gas operations in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), which requires us to reflect the effects of rate regulation in our financial statements. Use of SFAS No. 71 is applicable to our utility operations 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. As of December 31, 2003, we have concluded that the operations of ComEd and PECO meet the criteria. If we conclude in a future period that a separable portion of our business no longer meets the criteria, we are required to eliminate the financial statement effects of regulation for that part of our business, which would include the elimination of any regulatory assets and liabilities that had been recorded within our Consolidated Balance Sheets. The impact of not meeting the criteria of SFAS No. 71 could be material to our financial statements as a one time extraordinary item and through impacts on continuing operations. See Note 2 of the Notes to Consolidated Financial Statements for ComEd and PECO for further information regarding regulatory issues.

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. As of December 31, 2003, ComEd had recorded $1.9 billion of net regulatory liabilities, and PECO had recorded $5.3 billion of net regulatory assets within their Consolidated Balance Sheets. See Note 16 of the Notes to Consolidated Financial Statements for ComEd and Note 15 of the Notes to Consolidated Financial Statements for PECO for further information regarding their significant regulatory assets and liabilities.

For each regulatory jurisdiction where we conduct business, we continually assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or settlement. 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.

The electric businesses of 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. 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. If future recovery of costs ceases to be probable, the regulatory assets and liabilities would be recognized in current period earnings. A write-off of regulatory assets could impact ComEd or PECO’s ability to pay dividends under PUHCA and state law.

Nuclear Decommissioning (ComEd, PECO and Generation)

We account for our obligation to decommission our nuclear generating plants under SFAS No. 143 which requires that we make significant estimates of decommissioning costs to be incurred in future periods. We adopted SFAS No. 143 on January 1, 2003, and ComEd and Generation recorded income of $5 million and $108 million (net of income taxes), respectively, as a cumulative effect of a change in accounting principle. The adoption of SFAS No. 143 had no impact on PECO’s net income. For more information regarding the adoption and ongoing application of SFAS No. 143, see Note 10 of ComEd’s Notes to Consolidated Financial Statements, Note 9 of PECO’s Notes to Consolidated Financial Statements and Note 10 of Generation’s Notes to Consolidated Financial Statements.

Upon the adoption of SFAS No. 143, we were required to estimate the fair value of our obligation for the future decommissioning of our nuclear generating plants. To estimate the fair value of the decommissioning obligation, we used a probability-weighted, discounted cash flow model with multiple scenarios. Key assumptions used in the determination of fair value included the following:

Decommissioning Cost Studies.We used decommissioning cost studies prepared by a third party to provide a marketplace assessment of costs and the timing of retirement activities validated by comparison to current decommissioning projects and other third-party estimates.

Annual Cost Escalation Studies.Annual cost escalation studies were used to determine escalation factors based on inflation indices for labor, equipment and materials, energy, and low-level radioactive waste disposal costs.

Probabilistic Cash Flow Models.Our probabilistic cash flow models included the assignment of probabilities to various cost levels and various timing scenarios. The probability of various timing scenarios incorporated the factors of current license lives and life extensions and the timing of Department of Energy (DOE) acceptance for disposal of spent nuclear fuel.

Discount Rates.The estimated probability-weighted cash flows using these various scenarios were discounted using credit-adjusted, risk-free rates applicable to the various businesses.

Changes in the assumptions underlying the items discussed above could have materially affected the decommissioning obligation recorded upon the adoption of SFAS No. 143 and future costs related to decommissioning recorded in the consolidated financial statements. Under SFAS No. 143, the fair value of the nuclear decommissioning obligation is adjusted on an ongoing basis as the model input factors change.

Depreciable Lives of Property, Plant and Equipment (ComEd, PECO and Generation)

We have a significant investment in electric generation assets and electric and natural gas transmission and distribution assets. Depreciation of these assets is generally provided over their estimated service lives on a straight-line basis using the composite method. The estimation of service lives requires management judgment regarding the period of time that the assets will be in use. As circumstances warrant, depreciation estimates are reviewed to determine if any changes are needed. Effective July 1, 2002, ComEd decreased its depreciation rates based on a depreciation study, resulting in an annualized reduction in depreciation expense of $96 million. Effective April 1, 2001, Generation extended the estimated service lives of certain non-AmerGen generating

stations primarily based on service life extensions applied for with regulatory agencies, resulting in an annualized reduction in depreciation expense of $132 million. We anticipate extending the depreciable lives of the AmerGen stations beginning in January, 2004 concurrent with our initial full month of 100% ownership. Additional changes to depreciation estimates in future periods could have a significant impact on the amount of depreciation charged to the financial statements. Depreciation expense for the year ended December 31, 2003 was $308 million, $130 million, and $186 million for ComEd, PECO and Generation, respectively.

Asset Impairments

Long-Lived Assets and Investments (ComEd, PECO and Generation). We evaluate the carrying value of our long-lived assets, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. The review of assets for impairment requires significant assumptions about operating strategies and estimates of future cash flows. A variation in an assumption could result in a different conclusion regarding the realizability of the asset. The potential impact of recognizing an impairment of the assets reported within the Consolidated Balance Sheets, as well as on net income, could be and has been material to our consolidated financial statements.

In 2003, Generation recorded an impairment charge of $945 million (before income taxes) related to the long-lived assets of Boston Generating, an indirect wholly owned subsidiary of Generation, due to its decision to transition out of its ownership of Boston Generating. See Note 2 of Generation’s Notes to Consolidated Financial Statements for further information. In determining the amount of the impairment charge, Generation compared the carrying value of Boston Generating’s long-lived assets to their estimated fair value. The fair value was determined using estimated future discounted cash flows from those assets, which incorporated assumptions relative to the period of time that Generation will continue to own and operate Boston Generating. The time required to fully transition out of ownership of Boston Generating is uncertain and subject to change. Generation utilized a discount rate based upon valuations of the business developed at the purchase date. A change in the assumptions, including estimated cash flows and the discount rate, could have had a significant impact on the amount of the impairment charge recorded.

In 2003, Generation recorded impairment charges totaling $255 million (before income taxes) associated with a decline in the fair value of Generation’s investment in Sithe. In reaching that decision, Generation considered various factors, including negotiations to sell its investment in Sithe, which indicated an other-than-temporary decline in fair value.

In 2003, ComEd and PECO did not identify any factors through their review processes that indicated potential material impairment of property plant and equipment or other long-lived assets.

Goodwill (ComEd). ComEd had approximately $4.7 billion of goodwill recorded at December 31, 2003. ComEd performs an assessment for impairment of its goodwill at least annually, or more frequently, if events or circumstances indicate that goodwill might be impaired. Application of the goodwill impairment test requires judgment, including the identification of reporting units, assigning assets and liabilities to reporting units, assigning goodwill to reporting units, and determining the fair value of each reporting unit.

We performed our annual assessment of potential ComEd goodwill impairment for 2003 as of November 1, 2003, and determined that goodwill was not impaired. In our assessment, to estimate the fair value of the ComEd reporting unit, we used a probability-weighted, discounted cash flow model with multiple scenarios. The determination of the fair value is dependent on many sensitive, interrelated and uncertain variables, including changing interest rates, utility sector market performance, ComEd’s capital structure, market power prices, post-2006 rate regulatory structures, operating and capital expenditure requirements and other factors. Changes in these variables or in how they interrelate could result in a future impairment of goodwill at ComEd, which

could be material. For example, in the 2003 assessment, if estimated discounted cash flows had decreased by 5%, ComEd would have recorded a goodwill impairment of approximately $500 million.

Furthermore, based on certain anticipated reductions to cash flows subsequent to ComEd’s regulatory transition period (primarily CTCs), we believe there is a reasonable possibility that goodwill will be impaired at ComEd in 2004 or future years, and such impairment may be significant. The actual timing and amounts of goodwill impairments in future years, if any, will depend on the variables discussed above.

A goodwill impairment charge at ComEd may not affect Exelon’s results of operations as the goodwill impairment test for Exelon would consider cash flows of the entire Energy Delivery business segment, including both ComEd and PECO, and not just of ComEd.

Severance Accounting (ComEd, PECO and Generation)

As part of the implementation of The Exelon Way, we identified approximately 1,500 positions for elimination by the end of 2004, including 729, 166, and 470 positions at ComEd, PECO and Generation, respectively. We provide severance benefits to terminated employees pursuant to pre-existing severance plans primarily based upon each individual employee’s years of service with us and compensation level. We recorded charges in 2003 related to severance benefits that were considered probable and could be reasonably estimated in accordance with SFAS No. 112, “Employer’s Accounting for Postemployment Benefits, an amendment of FASB Statements No. 5 and 43” (SFAS No. 112). A significant assumption in calculating the severance charge was the determination of the number of positions to be eliminated. We based our estimates on our current plans and our ability to determine the appropriate staffing levels to effectively operate the businesses. We are considering whether there are additional positions to be eliminated in 2005 and 2006. We may incur further severance costs associated with The Exelon Way if additional positions are identified for elimination. These costs will be recorded in the period in which the costs can be reasonably estimated.

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 substantially all ComEd, PECO, Generation and BSC employees and certain Enterprises employees. See Note 14 of Exelon’s Notes to Consolidated Financial Statement for further information regarding the accounting for our defined benefit pension plans and postretirement welfare benefit plans.

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, we utilize 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.

The selection of key actuarial assumptions utilized in the measurement of the plan obligations and costs drives the results of the analysis and the resulting charges. The long-term expected rate of return on plan assets (EROA) assumption used in calculating 2003 pension cost was 9.00% compared to 9.50% for 2002 and 2001. The weighted average EROA assumption used in calculating 2003 other postretirement benefit costs was 8.40% compared to 8.80% for 2002 and 2001. 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. The Moody’s Aa Corporate Bond Index was used as the basis in selecting the discount rate for determining the plan obligations, using 6.25% at December 31, 2003 compared to 6.75% at December 31, 2002 and 7.35% at December 31, 2001. The reduction in discount rate is due to the decline in Moody’s Aa Corporate Bond Index in 2003 and 2002.

The following tables illustrate the aggregate effects of changing the major actuarial assumptions discussed above:


Change in Actuarial Assumption	Impact on Projected Benefit Obligation at December 31, 2003		Impact on Pension Liability at December 31, 2003		Impact on 2004 Pension Cost
Pension benefits
Decrease discount rate by 0.5%	$	548	$	481	$	37
Decrease rate of return on plan assets by 0.5%		—		—		34

Change in Actuarial Assumption	Impact on Other Postretirement Benefit Obligation at December 31, 2003		Impact on Postretirement Benefit Liability at December 31, 2003		Impact on 2004 Postretirement Benefit Cost
Postretirement benefits
Decrease discount rate by 0.5%	$	178	$	—	$	20
Decrease rate of return on plan assets by 0.5%		—		—		5

The assumptions are reviewed at the beginning of each year during our annual review process and at any interim remeasurement of the plan obligations. The impact of assumption changes is reflected in the recorded pension amounts as they occur, or over a period of time if allowed under applicable accounting standards. As these assumptions change from period to period, recorded pension amounts and funding requirements could also change.

ComEd, PECO and Generation incurred approximately $131 million, $57 million and $112 million, respectively, of pension and postretirement benefit costs in 2003, inclusive of curtailment costs associated with The Exelon Way of $48 million, $10 million, and $18 million, respectively. Although 2004 pension and postretirement benefit costs will depend on market conditions, Exelon’s estimate is that its pension and postretirement benefit costs, in the aggregate, will not change significantly in 2004 as compared to 2003.

Taxation (ComEd, PECO and Generation)

ComEd, PECO and Generation are required to make judgments regarding the potential tax effects of various financial transactions and our ongoing operations to estimate our obligations to taxing authorities. These tax obligations include income, real estate, use and employment-related taxes and ongoing appeals related to these tax matters. These judgments include reserves for potential adverse outcomes regarding tax positions that we have taken. Generation must also assess its ability to generate capital gains in future periods to realize tax benefits associated with capital losses expected to be generated in future periods. Capital losses may be deducted only to the extent of capital gains realized during the year of the loss or during the three prior or five succeeding years. As of December 31, 2003, Generation has not recorded an allowance against its deferred tax assets associated with impairment losses which will become capital losses when realized for income tax purposes. Generation believes these deferred tax assets will be realized in future periods. While we believe the resulting tax reserve balances as of December 31, 2003 reflect the most likely probable expected outcome of these tax matters in accordance with SFAS No. 5, “Accounting for Contingencies,” and SFAS No. 109, “Accounting for Income Taxes,” the ultimate outcome of such matters could result in additional adjustments to our consolidated financial statements and such adjustments could be material.

Unbilled Energy Revenues (ComEd, PECO and Generation)

Revenues related to the sale of energy by ComEd and PECO 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 or gas throughput volume, estimated customer usage by class, estimated losses of energy during delivery to customers and applicable customer rates. Customer accounts receivable as of December 31, 2003 include unbilled energy revenues of $225 million and $143 million for ComEd and PECO, respectively. 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; however, total revenues would remain unchanged.

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 are recorded. This unbilled revenue is estimated each month based on daily customer demand, fixed quantity sales, generation volume and applicable market or fixed rates. Generation’s customer accounts receivable as of December 31, 2003 include unbilled energy revenues of $366 million. 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, 2003, ComEd, PECO and Generation had accrued liabilities of $69 million, $50 million and $10 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 and costs of expenditures can be reliably estimated, amounts are discounted. These amounts represent $64 million and $41 million of the accrued liabilities above for ComEd and PECO, respectively. Where timing and amounts cannot be reliably estimated, amounts are recognized on an undiscounted basis. Such amounts represent $5 million, $9 million, and $10 million of the accrued liabilities total for ComEd, PECO and Generation, respectively. Estimates can be affected by the factors noted above as well as by changes in technology, regulations or the requirements of local governmental authorities.

ComEd

Executive Summary

2003 has been a year of operating accomplishments. ComEd has focused on living up to its reliability and safety commitments while pursuing greater productivity, quality and innovation. Here are just a few of the 2003 highlights:

Financial Results.ComEd experienced an overall decline in net income of 11% in 2003.This decline was primarily due to lower operating revenues as a result of unfavorable weather and customers purchasing energy from an ARES or PPO and higher operating and maintenance expense including the costs associated with implementing The Exelon Way. ComEd’s 2003 results were favorably affected by lower depreciation and amortization expense, lower purchased power expense and lower interest expense.

The Exelon Way.ComEd implemented The Exelon Way, an aggressive, long-term operational plan defining how ComEd will conduct business in years to come. The Exelon Way is focused on improving operating cash flows while meeting service and financial commitments through improved integration of operations and consolidation of support functions. Exelon’s targeted annual cash savings range from approximately $300 million in 2004 to approximately $600 million in 2006. ComEd recorded severance and severance-related after-tax charges during 2003 associated with the implementation of The Exelon Way and is considering whether it will incur additional severance related costs in future periods.

Investment Strategy. ComEd continued to invest in its infrastructure spending over $700 million in 2003 and expects to invest over $600 million in 2004.

Financing Activities. ComEd issued debt and equity securities to refinance approximately $1.7 billion and repaid approximately $260 million of outstanding debt, approximately $340 million of transitional trust notes and $52 million of commercial paper in 2003, resulting in annual interest savings of $65 million. ComEd met all of its capital resource commitments with internally generated cash and expects to do so in the foreseeable future.

Operational Achievements. ComEd’s business focused on the core fundamentals of providing reliable delivery service. Following several years of continued reliability improvement, ComEd’s performance dipped slightly in 2003 due to a series of severe storms across Northern Illinois - two of which were the worst since 1998.

Outlook for 2004 and Beyond.In the short term, ComEd’s financial results will be affected by a number of factors, including weather conditions and successful implementation of The Exelon Way. If weather is warmer than normal in the summer months or colder than normal in the winter months, operating revenues at ComEd generally will be favorably affected. In addition, ComEd is required annually to assess its goodwill to determine if it is impaired. Based on certain anticipated reductions to cash flows subsequent to the transition period (primarily competitive transition charges), ComEd believes there is a reasonable possibility that goodwill may be impaired in 2004 or future periods, and such impairment may be significant.

Longer term, restructuring in the U.S. electric industry is at a crossroads at both the Federal and state levels, with continuing debate at the FERC on regional transmission organization (RTO) and standard market platform issues and in many states on the “post transition” format. Some states abandoned failed transition plans (like California), some states are adjusting current transition plans (like New Jersey and Ohio) and the state of Illinois (by 2007) is considering options to preserve choice for large customers and rate stability for mass market customers, while ensuring the financial returns needed for continuing investments in reliability. ComEd will continue to be an active participant in these policy debates, while continuing to focus on improving operations and controlling costs.

As ComEd nears the end of the restructuring transition period and related rate freeze in Illinois, ComEd will also continue to work with Federal and state regulators, state and local governments, customer representatives and other interested parties to develop appropriate processes for establishing future rates in restructured

electricity markets. ComEd will strive to ensure that future rate structures recognize the substantial improvements ComEd has made, and will continue to make, in its transmission and distribution systems. ComEd will also work to ensure that its rates adequately compensate its suppliers, which could include Generation, for the costs associated with procuring full-load following capacity energy supplies given ComEd’s Provider of Last Resort (POLR) obligations. As in the past, by working together with all interested parties, ComEd believes it can successfully meet these objectives and obtain fair recovery of its costs for providing service to its customers. However, if ComEd is unsuccessful, its results of operations and cash flows could be negatively affected after the transition period.

While the U.S. economic recovery appears underway, ComEd’s current plans are based on moderate kilowatthour sales growth (1% to 2%). Successful implementation of The Exelon Way is needed to offset labor and material cost escalation, especially the double digit increases in health care costs. ComEd’s stable base of over three million customers will provide a solid platform with which to meet these challenges.

Results of Operations

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

Significant Operating Trends – ComEd


	2003			2002			Variance			% Change
OPERATING REVENUES	$	5,814		$	6,124		$	(310	)	(5.1	)%

OPERATING EXPENSES
Purchased power		2,501			2,585			(84	)	(3.2	)%
Operating and maintenance		1,093			964			129		13.4	%
Depreciation and amortization		386			522			(136	)	(26.1	)%
Taxes other than income		267			287			(20	)	(7.0	)%

Total operating expense		4,247			4,358			(111	)	(2.5	)%

OPERATING INCOME		1,567			1,766			(199	)	(11.3	)%

OTHER INCOME AND DEDUCTIONS
Interest expense		(423	)		(484	)		61		(12.6	)%
Distributions on mandatorily redeemable preferred securities		(26	)		(30	)		4		(13.3	)%
Other, net		49			44			5		11.4	%

Total other income and deductions		(400	)		(470	)		70		(14.9	)%

INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		1,167			1,296			(129	)	(10.0	)%

INCOME TAXES		465			506			(41	)	(8.1	)%

INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		702			790			(88	)	(11.1	)%
CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE, (net of income taxes)		5			—			5		n.m.

NET INCOME	$	707		$	790		$	(83	)	(10.5	)%

n.m.	not meaningful

Net Income

Net income was affected by lower operating revenues primarily due to unfavorable weather and customers purchasing energy from an ARES or PPO and higher operating and maintenance expense, partially offset by lower depreciation and amortization expense, lower purchased power expense and lower interest expense.

Operating Revenues

ComEd’s electric sales statistics are as follows:


Retail Deliveries – (in GWhs) (1)	2003	2002	Variance		% Change
Bundled deliveries(2)
Residential	26,206	27,474	(1,268	)	(4.6	)%
Small commercial & industrial	21,541	22,365	(824	)	(3.7	)%
Large commercial & industrial	5,921	7,885	(1,964	)	(24.9	)%
Public authorities & electric railroads	5,125	6,480	(1,355	)	(20.9	)%

	58,793	64,204	(5,411	)	(8.4	)%

Unbundled deliveries(3)
ARES
Small commercial & industrial	6,006	5,219	787		15.1	%
Large commercial & industrial	9,909	7,095	2,814		39.7	%
Public authorities & electric railroads	1,402	912	490		53.7	%

	17,317	13,226	4,091		30.9	%

PPO
Small commercial & industrial	3,318	3,152	166		5.3	%
Large commercial & industrial	4,348	5,131	(783	)	(15.3	)%
Public authorities & electric railroads	1,925	1,347	578		42.9	%

	9,591	9,630	(39	)	(0.4	)%

Total unbundled deliveries	26,908	22,856	4,052		17.7	%

Total retail deliveries	85,701	87,060	(1,359	)	(1.6	)%

(1)	One GWh is the equivalent of one million kWhs.

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

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


Electric Revenue	2003		2002		Variance			% Change
Bundled revenues(1)
Residential	$	2,272	$	2,381	$	(109	)	(4.6	)%
Small commercial & industrial		1,667		1,736		(69	)	(4.0	)%
Large commercial & industrial		304		410		(106	)	(25.9	)%
Public authorities & electric railroads		316		377		(61	)	(16.2	)%

		4,559		4,904		(345	)	(7.0	)%

Unbundled Revenues(2)
ARES
Small commercial & industrial		139		138		1		0.7	%
Large commercial & industrial		175		154		21		13.6	%
Public authorities & electric railroads		33		28		5		17.9	%

		347		320		27		8.4	%

PPO
Small commercial & industrial		225		204		21		10.3	%
Large commercial & industrial		240		278		(38	)	(13.7	)%
Public authorities & electric railroads		103		71		32		45.1	%

		568		553		15		2.7	%

Total unbundled revenues		915		873		42		4.8	%

Total electric retail revenues		5,474		5,777		(303	)	(5.2	)%
Wholesale and miscellaneous revenue (3)		340		347		(7	)	(2.0	)%

Total electric revenue	$	5,814	$	6,124	$	(310	)	(5.1	)%

(1)	Bundled revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy.

(2)

Revenue from customers choosing an ARES includes a distribution charge and a CTC charge. Transmission charges received from ARES are included in wholesale and miscellaneous revenue. Revenues from customers choosing the PPO includes an energy charge at market rates, transmission and distribution charges, and a CTC charge.

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

The changes in electric retail revenues in 2003, as compared to 2002, were attributable to the following:


	Variance
Weather	$	(232	)
Customer choice		(155	)
Rate changes		(33	)
Volume		105
Other effects		12

Retail revenue	$	(303	)

Weather.The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity. Conversely, mild weather reduces demand. The weather impact for the year ended December 31, 2003 was unfavorable compared to the same period in 2002 as a result of cooler summer weather in 2003. Cooling degree-days decreased 36% in the year ended December 31, 2003 compared to the same period in 2002 and were partially offset by a 5% increase in heating degree days in the year ended December 31, 2003 compared to the same period in 2002.

Customer Choice.All ComEd customers have the choice to purchase energy from other suppliers. This choice generally does not impact the volume of deliveries, but affects revenue collected from customers related to energy supplied by ComEd. However, as of December 31, 2003, no ARES has sought approval from the ICC, and no electric utilities have chosen, to enter the ComEd residential market for the supply of electricity. The decrease in revenues reflects increased non-residential customers in Illinois electing to purchase energy from an ARES or the PPO.

For the year ended December 31, 2003, the energy provided by alternative electric generation suppliers was 17,317 GWhs, or 20.2% of total retail deliveries, as compared to 13,226 GWhs, or 15.2%, for the year ended December 31, 2002.

As of December 31, 2003 and 2002, the number of retail customers that had elected to purchase energy from an ARES or the ComEd PPO was approximately 20,300 and 22,700, respectively, representing less than 1% of total customers in each year. Deliveries to such customers increased from 22,856 GWhs for the year ended December 31, 2002 to 26,908 GWhs for the year ended December 31, 2003, or from 26% to 31% of total annual retail deliveries.

Rate Changes. The decrease in revenues attributable to rate changes reflects lower wholesale market prices in the first six months of 2003, which were partially offset by higher wholesale market prices in the last six months of 2003, decreasing revenue received under ComEd’s PPO by $31 million. Starting in the June 2003 billing cycle, the increased wholesale market price of electricity, net of increased mitigation factors, as a result of the Agreement described in Note 2 of ComEd’s Notes to Consolidated Financial Statements, decreased the collection of CTCs as compared to the respective period in 2002. However, for the two-year period, CTC revenues were consistent.

Volume.Revenues from higher delivery volume, exclusive of weather, increased due to an increased number of customers and increased usage per customer, primarily large and small commercial and industrial.

Wholesale and miscellaneous revenue for the year ended December 31, 2003 compared to the year ended December 31, 2002 decreased $7 million primarily due to a 2002 reimbursement from Generation of $12 million.

Purchased Power

Purchased power expense decreased in 2003 primarily due to a $135 million decrease as a result of customers choosing to purchase energy from an ARES, a $115 million decrease due to unfavorable weather and a $20 million decrease due to additional energy billed in 2002 under the PPA with Generation, partially offset by an increase of $74 million due to pricing changes related to ComEd’s PPA with Generation, an increase of $62 million under the PPA related to decommissioning collections associated with the adoption of SFAS No. 143 that were not included in purchased power in 2002 and an increase of $59 million due to higher volume. The $62 million increase in purchased power expense related to SFAS No. 143 had no impact on net income as it was offset by lower regulatory asset amortization expense (see Depreciation and Amortization below).

Operating and Maintenance

Operating and maintenance (O&M) expense increased in 2003 reflecting $137 million due to The Exelon Way severance and related postretirement health and welfare benefits accruals and pension and postretirement curtailment costs, a net charge of $41 million in 2003 as the result of the Agreement as more fully described in Note 2 of ComEd’s Notes to Consolidated Financial Statements, $14 million of additional storm-related costs and $7 million increase in employee fringe benefits partially offset by $78 million decrease in payroll expenses due to fewer employees and $6 million lower net manufactured gas plant (MGP) investigation and remediation reserve charges.

Depreciation and Amortization

Depreciation and amortization expense decreased in 2003 as follows:


	2003		2002		Variance			% Change
Depreciation expense	$	308	$	334	$	(26	)	(7.8	)%
Recoverable transition costs amortization		44		102		(58	)	(56.9	)%
Other amortization expense		34		86		(52	)	(60.5	)%

Total depreciation and amortization	$	386	$	522	$	(136	)	(26.1	)%

The decrease in depreciation expense is primarily due to lower depreciation rates effective July 1, 2002, partially offset by higher property, plant and equipment balances. The lower rates followed completion of a depreciation study and reflect ComEd’s 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 reduction in depreciation expense was $48 million ($29 million, net of income taxes) in 2003 compared to 2002.

Recoverable transition costs amortization decreased in the year ended December 31, 2003 compared to the same period in 2002. The decrease is a result of additional amortization in 2002. ComEd expects to fully recover its recoverable transition costs regulatory asset balance of $131 million by 2006. Consistent with the provision 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 decrease in other amortization primarily relates to the reclassification of a regulatory asset for nuclear decommissioning as a result of the adoption of SFAS No. 143 in 2003 (see Note 10 of ComEd’s Notes to Consolidated Financial Statements). This decrease had no impact on net income as it was offset by increased purchased power from Generation (see Purchased Power above).

Taxes Other Than Income

Taxes other than income decreased in 2003 primarily as a result of a $25 million credit in 2003 for use tax payments for periods prior to the Merger and a $5 million refund in 2003 of Illinois Electricity Distribution taxes, partially offset by $8 million in Illinois Public Utility Fund taxes in 2003 that were not charged in 2002 and a $5 million real estate tax refund in 2002.

Interest Charges

Interest charges consist of interest expense and distributions on mandatorily redeemable preferred securities. Interest charges decreased in 2003 due to the impact of lower interest rates as a result of refinancing existing debt at lower interest rates for 2003 as compared to 2002 and the pay down of $340 million in ComEd Transitional Trust Notes.

Other, Net

Other, net increased in 2003 as compared to 2002. In 2002, ComEd recorded a $12 million reserve accrual for a potential plant disallowance from an audit performed in conjunction with ComEd’s delivery services rate case. This $12 million was reversed in March 2003 as a result of the Agreement – as more fully described in Note 2 to ComEd’s Notes to Consolidated Financial Statements. These items were partially offset by a $9 million reduction in intercompany interest income from Unicom Investments Inc., reflecting a lower principal balance, and a $10 million decrease in various other income and deduction items.

Income Taxes

The effective income tax rate was 39.8% in 2003 as compared to 39.0% in 2002.

Due to revenue needs of the states in which ComEd operates, various state income tax and fee increases have been proposed or are being contemplated. If these changes are enacted, they could increase ComEd’s state income tax expense. At this time, however, ComEd cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by the state legislatures or regulatory bodies, and, if enacted, whether any such legislation or regulation would be effective retroactively or prospectively. As a result, ComEd cannot currently estimate the effect of these potential changes in tax laws or regulation.

Cumulative Effect of a Change in Accounting Principle

On January 1, 2003, ComEd adopted SFAS No. 143, resulting in income of $5 million, net of tax. See Note 10 of ComEd’s Notes to Consolidated Financial Statements for further discussion of the adoption of SFAS No. 143.

Results of Operations

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

Significant Operating Trends – ComEd


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

OPERATING EXPENSES
Purchased power		2,585			2,670			(85	)	(3.2	)%
Operating and maintenance		964			981			(17	)	(1.7	)%
Depreciation and amortization		522			665			(143	)	(21.5	)%
Taxes other than income		287			296			(9	)	(3.0	)%

Total operating expense		4,358			4,612			(254	)	(5.5	)%

OPERATING INCOME		1,766			1,594			172		10.8	%

OTHER INCOME AND DEDUCTIONS
Interest expense		(484	)		(565	)		81		(14.3	)%
Distributions on mandatorily redeemable preferred securities		(30	)		(30	)		—		—
Other, net		44			114			(70	)	(61.4	)%

Total other income and deductions		(470	)		(481	)		11		(2.3	)%

INCOME BEFORE INCOME TAXES		1,296			1,113			183		16.4	%

INCOME TAXES		506			506			—		—

NET INCOME	$	790		$	607		$	183		30.1	%

Net Income

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

Operating Revenues

ComEd’s electric sales statistics are as follows:


Retail Deliveries – (in GWhs)	2002	2001	Variance		% Change
Bundled deliveries(1)
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(2)
ARES
Small commercial & industrial	5,219	2,865	2,354		82.2	%
Large commercial & industrial	7,095	5,458	1,637		30.0	%
Public authorities & electric railroads	912	365	547		149.9	%

	13,226	8,688	4,538		52.2	%

PPO
Small commercial & industrial	3,152	3,279	(127	)	(3.9	)%
Large commercial & industrial	5,131	5,750	(619	)	(10.8	)%
Public authorities & electric railroads	1,347	987	360		36.5	%

	9,630	10,016	(386	)	(3.9	)%

Total unbundled deliveries	22,856	18,704	4,152		22.2	%

Total Retail Deliveries	87,060	85,605	1,455		1.7	%

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

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


Electric Revenue	2002		2001		Variance			% Change
Bundled Revenues(1)
Residential	$	2,381	$	2,308	$	73		3.2	%
Small commercial & industrial		1,736		1,821		(85	)	(4.7	)%
Large commercial & industrial		410		523		(113	)	(21.6	)%
Public authorities & electric railroads		377		430		(53	)	(12.3	)%

		4,904		5,082		(178	)	(3.5	)%

Unbundled Revenues(2)
ARES
Small commercial & industrial		138		48		90		187.5	%
Large commercial & industrial		154		74		80		108.1	%
Public authorities & electric railroads		28		5		23		n.m.

		320		127		193		152.0	%

PPO
Small commercial & industrial		204		220		(16	)	(7.3	)%
Large commercial & industrial		278		343		(65	)	(19.0	)%
Public authorities & electric railroads		71		59		12		20.3	%

		553		622		(69	)	(11.1	)%

Total unbundled revenues		873		749		124		16.6	%

Total electric retail revenues		5,777		5,831		(54	)	(0.9	)%
Wholesale and miscellaneous revenue (3)		347		375		(28	)	(7.5	)%

Total electric revenue	$	6,124	$	6,206	$	(82	)	(1.3	)%

(1)	Bundled revenue reflects deliveries to customers taking electric service under tariffed rates, which include the cost of energy and the delivery cost of the transmission and the distribution of the energy.

(2)

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

n.m.	not meaningful

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


	Variance
Customer choice	$	(131	)
Rate changes		(99	)
Weather		88
Volume		91
Other effects		(3	)

Retail revenue	$	(54	)

Customer Choice. The decrease in revenues reflects customers in Illinois electing to purchase energy from an ARES or the PPO. As of December 31, 2002, approximately 22,700 retail customers had elected to purchase energy from an ARES or the ComEd PPO, an increase from 18,700 customers at December 31, 2001. Deliveries to such customers increased from 18,704 GWhs in 2001 to 22,856 GWhs in 2002, a 22% increase from the previous year.

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

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

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

The reduction in wholesale and miscellaneous revenue in 2002 as compared to 2001 was due primarily to a $38 million decrease in off-system sales due to the expiration of wholesale contracts that were offered by ComEd from June 2000 to May 2001 to support the open access program in Illinois, and a $15 million reversal of reserve for revenue refunds in 2001 related to certain of ComEd’s municipal customers as a result of a favorable FERC ruling, partially offset by a reimbursement from Generation of $12 million for third-party energy reconciliations and $13 million of other miscellaneous revenue.

Purchased Power

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 decrease in 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 in 2002 as follows:


	2002		2001		Variance			% Change
Depreciation expense	$	334	$	353	$	(19	)	(5.4	)%
Recoverable transition costs amortization		102		108		(6	)	(5.6	)%
Other amortization expense		86		204		(118	)	(57.8	)%

Total depreciation and amortization	$	522	$	665	$	(143	)	(21.5	)%

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

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

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

Taxes Other Than Income

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

Interest Charges

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

The decrease in other income and deductions, excluding interest charges, 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.

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, participation in the intercompany money pool or capital contributions from Exelon. 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. If these conditions deteriorate to where ComEd no longer has access to external financing sources at reasonable terms, ComEd has access to a revolving credit facility that ComEd currently utilizes to support its commercial paper program. See the Credit Issues section of Liquidity and Capital Resources for further discussion. Capital resources are used primarily to fund ComEd’s capital requirements, including construction, repayments of maturing debt, the payment of dividends and contributions to Exelon’s pension plans.

As part of the implementation of The Exelon Way, ComEd identified 729 positions, including professional, managerial and union employees, for elimination by the end of 2004 and recorded a charge for salary continuance severance of $61 million before income taxes during 2003, which ComEd anticipates that the majority will be paid in 2004 and 2005. ComEd is considering whether there are additional positions to be eliminated in 2005 and 2006. ComEd may incur further severance-related costs associated with The Exelon Way if additional positions are identified to be eliminated. These costs will be recorded in the period in which the costs can be reasonably estimated.

Cash Flows from Operating Activities

ComEd’s cash flow from operating activities primarily results from sales of electricity to a stable and diverse base of retail customers at fixed prices. ComEd’s future cash flows will depend upon the ability to achieve operating cost reductions, and the impact of the economy, weather and customer choice on its revenues. Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flow, sufficient to meet operating and capital expenditures requirements. Operating cash flows after 2006 could be negatively affected by changes in ComEd’s rate regulatory environment, although any effects are not expected to hinder ComEd’s ability to fund its business requirements. See Business Outlook and Challenges in Managing our Business.

Cash flows provided by operations for the years ended December 31, 2003 and 2002 were $948 million and $1,664 million, respectively. Changes in ComEd’s cash flows from operations are generally consistent with changes in its results of operations, as further adjusted by changes in working capital in the normal course of business.

In addition to the items mentioned in Results of Operations, ComEd’s operating cash flows in 2003 were affected by the following items:

•

Payments to Generation in 2003 for amounts owed under the PPA. At December 31, 2003 and 2002, ComEd had accrued payments due to Generation under the PPA of $171 million and $339 million, respectively.

•

Discretionary contributions to Exelon’s defined benefit pension plans of $178 million in 2003 compared to $82 million in 2002.

ComEd participates in Exelon’s defined benefit pension plans. Exelon’s plans currently meet the minimum funding requirements of the Employment Retirement Income Act of 1974; however, Exelon expects to make a discretionary pension plan contribution up to approximately $419 million in 2004, of which, $216 million is expected to be funded by ComEd.

Cash Flows from Investing Activities

Cash flows used in investing activities were $893 million in 2003 compared to $783 million in 2002. The increase in cash flows used in investing activities was primarily attributable to a $405 million investment in the Exelon intercompany money pool partially offset by the receipt of $213 million from Unicom Investments Inc. related to an intercompany note payable and a $68 million decrease in capital expenditures. ComEd’s investing activities for the year ended December 31, 2003 were funded primarily through operating activities.

ComEd estimates that it will spend approximately $616 million in total capital expenditures for 2004. Approximately one half of the budgeted 2004 expenditures are for continuing efforts to improve the reliability of its transmission and distribution systems. The remaining amount 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 debt or 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 2003 were $37 million as compared to $888 million in 2002. The decrease in cash flows used in financing activities is primarily attributable to increased issuances of debt, including debt to affiliates and preferred securities, of $945 million, a $107 million increase in contributions from parent and a $69 million decrease in dividend payments to Exelon, partially offset by a $142 million change in

commercial paper activity, a $74 million increase in debt and preferred securities redemptions and increased interest-rate swap settlement of $35 million. ComEd paid a $401 million dividend to Exelon during 2003 compared to a $470 million dividend in 2002.

Credit Issues

Exelon Credit Facility. ComEd meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from Exelon’s intercompany money pool. In October 2003, Exelon, ComEd, PECO and Generation replaced their $1.5 billion bank unsecured revolving credit facility with a $750 million 364-day unsecured revolving credit agreement and a $750 million 3-year unsecured revolving credit agreement with a group of banks. Both revolving credit agreements are used principally to support the commercial paper programs at Exelon, ComEd, PECO and Generation and to issue letters of credit. The 364-day agreement also includes a term-out option provision that allows a borrower to extend the maturity of revolving credit borrowings outstanding at the end of the 364-day period for one year.

At December 31, 2003, ComEd’s aggregate sublimit under the credit agreements was $100 million. Sublimits under the credit agreements can change upon written notification to the bank group. ComEd had approximately $80 million of unused bank commitments under the credit agreements at December 31, 2003. ComEd did not have any commercial paper outstanding at December 31, 2003. At December 31, 2002, ComEd’s Consolidated Balance Sheet reflected $123 million in commercial paper outstanding of which $52 million was classified as long-term debt. Interest rates on the advances under the credit agreements are based on either the London Interbank Offering Rate (LIBOR) or prime plus an adder based on the credit rating of the borrower as well as the total outstanding amounts under the agreement at the time of borrowing. The maximum adder would be 175 basis points.

For 2003, the average interest rate on notes payable was approximately 1.47%. 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 agreements cannot be less than 2.25 to 1 for the twelve-month period ended December 31, 2003. At December 31, 2003, ComEd was in compliance with the credit agreement thresholds.

Capital Structure.At December 31, 2003, ComEd’s capital structure consisted of 34% long-term debt, 16% long-term debt to affiliates, and 50% common equity. At December 31, 2003, ComEd’s capital structure, excluding the deduction from shareholders’ equity of the $250 million receivable from Exelon (which amount is deducted for GAAP purposes but is excluded here to reflect amounts expected to be received by ComEd from Exelon to pay future taxes), consisted of 34% long-term debt, 15% long-term debt to affiliates, and 51% common equity. Long-term debt to affiliates includes obligations to ComEd Financing II, ComEd Financing III and the ComEd Transitional Funding Trust, which are no longer consolidated within the financial statements due to the adoption of FASB Interpretation No. 46-R “Consolidation of Variable Interest Entities” (FIN No. 46-R) as of December 31, 2003.

Intercompany Money Pool. To provide an additional short-term borrowing option that could 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 Exelon’s corporate treasurer. ComEd and its subsidiary, Commonwealth Edison of Indiana, Inc. (ComEd of Indiana), PECO, Generation and BSC may participate in the money pool as lenders and borrowers, and Exelon Corporate may participate as a lender. Funding of, and borrowings from, the money pool are predicated on whether the contributions and borrowings result in economic benefits. Interest on borrowings is based on short-term market rates of interest, or, if from an external source, specific borrowing rates. ComEd’s maximum amount of investment at any time during 2003 was $483 million. At December 31, 2003, ComEd’s contribution outstanding was $405 million. During 2003, ComEd earned $2 million in interest on its investments in the intercompany money pool.

Security Ratings.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. In the fourth quarter of 2003, Standard & Poor’s Ratings Services affirmed ComEd’s corporate credit ratings but revised its outlook to negative from stable. None of ComEd’s borrowings is subject to default or prepayment as a result of a downgrading of securities ratings although such a downgrading could increase fees and interest charges under certain bank credit facilities. The following table shows ComEd’s securities ratings at December 31, 2003:


Securities	Moody’s Investors Service	Standard & Poor’s	Fitch Ratings
Senior secured debt	A3	A-	A-
Commercial paper	P2	A2	F2
Transition bonds (1)	Aaa	AAA	AAA

(1)	Issued by ComEd Transitional Funding Trust, an unconsolidated affiliate of ComEd.

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.

Fund Transfer Restrictions.Under applicable federal law, ComEd can only pay dividends from retained or current earnings. Under Illinois law, ComEd may not pay any dividend on its stock unless “[its] earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEd has also agreed in connection with financings arranged through ComEd Financing II and ComEd Financing III (the Financing Trusts) that it will 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 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. At December 31, 2003, ComEd had retained earnings of $883 million, of which $709 million had been appropriated for future dividend payments. ComEd is precluded from lending or extending credit or indemnity to Exelon.

Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations

ComEd’s contractual obligations as of December 31, 2003 representing cash obligations that are considered to be firm commitments are as follows:


			Payment due within						Due after 5 Years
	Total		1 Year		2-3 Years		4-5 Years		Due after 5 Years
Long-term debt	$	4,396	$	236	$	889	$	644	$	2,627
Long-term debt to affiliates		2,037		317		680		680		360
Operating leases		116		14		24		23		55
Chicago agreement (1)		54		6		12		12		24
Regulatory commitments		30		10		20		—		—

Total contractual obligations	$	6,633	$	583	$	1,625	$	1,359	$	3,066

(1)

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:

•

long-term debt, see Note 8

•

operating leases, see Note 15

•

Midwest Agreement, see Note 15

•

regulatory commitments, see Note 2

See Note 15 to the Notes to Consolidated Financial Statements for discussion of ComEd’s commercial commitments as of December 31, 2003.

IRS Refund Claims

ComEd entered into several agreements with a tax consultant related to the filing of refund claims with the Internal Revenue Service (IRS) and has made refundable prepayments of $11 million for potential fees associated with these agreements. The fees for these agreements are contingent upon a successful outcome and are based upon a percentage of the refunds recovered from the IRS, if any. As such, ultimate net cash flows to ComEd related to these agreements will either be positive or neutral depending upon the outcome of the refund claim with the IRS. These potential tax benefits and associated fees could be material to ComEd’s financial position, results of operations and cash flows. ComEd’s tax benefits for periods prior to the Merger would be recorded as a reduction of goodwill pursuant to a reallocation of the Merger purchase price. ComEd cannot predict the timing of the final resolution of these refund claims.

Variable Interest Entities

Effective December 31, 2003, ComEd Financing II, ComEd Financing III, ComEd Funding LLC and ComEd Transitional Funding Trust were deconsolidated from the financial statements of ComEd in conjunction with the adoption of FIN No. 46-R. Approximately $2 billion of debt issued by ComEd to these financing trusts was recorded as debt to affiliates within the Consolidated Balance Sheet as of December 31, 2003.

Critical Accounting Policies and Estimates

See ComEd, PECO and Generation – Critical Accounting Policies and Estimates above for a discussion of ComEd’s critical accounting policies and estimates.

Business Outlook and the Challenges in Managing Our Business

ComEd conducts business in the electric transmission and distribution industry in the United States. That industry is in the midst of a fundamental and, at this point, uncertain transition from a fully regulated industry offering bundled service to an industry with unbundled services, some of which are regulated and others of which are priced in competitive markets. ComEd’s energy delivery business remains highly regulated and is capital intensive.

The challenges affecting ComEd’s businesses are discussed below. Further discussion of ComEd’s liquidity position and capital resources and related challenges is included in the Liquidity and Capital Resources section.

ComEd’s business is comprised of utility transmission and distribution operations, which provides electricity to customers in Illinois.

Illinois has adopted restructuring legislation designed to foster competition in the retail sale of electricity. As a result of these restructuring initiatives, ComEd is subject to rate freezes through a mandated restructuring transition period ending on December 31, 2006. During this period, ComEd’s results of operations will depend on its ability to deliver energy in a cost-efficient manner and to offset infrastructure investments and inflation with cost savings initiatives. ComEd expects to continue to have long-term, full-requirements supply contracts with Generation, helping to mitigate the risk of changing energy supply costs during the transition period.

ComEd is also managing operations and maintenance costs by implementing The Exelon Way business model, while maintaining a focus on both reliability and safety in operating the business.

ComEd cannot currently predict the framework that will be used by the Illinois state regulators to establish rates after the transition period. ComEd also cannot predict the outcome of any new laws that may impact its business. Nevertheless, ComEd expects to retain significant POLR obligations, whereby it is required to provide service to customers in its service area. ComEd therefore must continue to ensure adequate supplies of electricity are available at reasonable costs. While ComEd does not have its own generation capabilities, ComEd believes its ongoing relationship with Generation will serve to lessen the supply and price risks associated with its expected ongoing power procurement responsibilities.

More detailed explanations for each of these and other challenges in managing the business are as follows:

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 the utilities 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 the state and Federal agencies affect the manner in which ComEd does business, its ability to undertake specified actions, the costs of operations, and the level of rates charged to recover such costs.

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

Rate freezes and caps 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 to deliver electricity in a cost-efficient manner and to realize cost savings under The Exelon Way 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 in effect 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 provision and currently does not expect to trigger the earnings sharing provision in the years 2004 through 2006.

ComEd’s long-term purchased power agreements provide a partial hedge to its customers’ demand.

To effectively manage its obligation to provide power to meet its customers’ demand, ComEd has established full-requirements, power supply agreements with Generation which reduce exposure to the volatility of customer demand and market prices through 2006. These agreements fix the price of energy, and under the PPA, prices for energy vary depending upon the time of day and month of delivery. Market prices relative to ComEd’s regulated rates still influence switching behavior among retail customers.

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 expects to continue 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 further expects those capital expenditures will exceed depreciation on its plant assets. ComEd’s base rate freeze and caps will generally preclude incremental rate recovery on any of these incremental investments prior to January 1, 2007.

ComEd’s business may be significantly affected by the end of the Illinois regulatory transition period.

Illinois electric utilities are allowed to collect CTCs from customers who choose an alternative supplier of electric generation service or choose ComEd’s PPO. CTCs were intended to assist electric utilities, such as ComEd, in recovering stranded costs that might not otherwise be recoverable in a fully competitive market. The CTC charge represents the difference between the market value of delivered energy (the sum of generation service at market based 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.

In 2003 and 2002, ComEd collected approximately $300 million of CTC revenue annually. As a result of increasing mitigation factors, changes in energy prices and the ability of certain customers to establish fixed, multi-year CTC rates beginning in 2003, ComEd anticipates that this revenue source will decline to approximately $180 million to $200 million in each of the years 2004 through 2006. Under the current restructuring statute, no CTCs will be collected after 2006.

Through 2006, ComEd will continue to have an obligation to offer bundled service to all customers (except certain large customers with demand of three megawatts or more) at frozen price levels, under which a majority of its residential and small commercial customers are expected to continue to receive service. 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. 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 continually working with Illinois state and business community leadership to facilitate the development of a competitive electricity market while providing system reliability. 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 and ComEd is pursuing measures that will provide greater productivity, quality and innovation in its work practices. Currently, it is difficult to predict the framework for or the outcome of a potential regulatory proceeding to establish rates after 2006.

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

ComEd has approximately $4.7 billion of goodwill recorded at December 31, 2003. 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 annual 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 by ComEd. Under Illinois statute, any impairment of goodwill has no impact on the determination of ComEd’s rate cap through the transition period.

Goodwill has not been impaired to date. However, based on certain anticipated reductions to cash flows (primarily CTCs) subsequent to ComEd’s regulatory transition period, ComEd believes there is a reasonable possibility that goodwill will be impaired at ComEd in 2004 or later periods. The actual timing and amounts of goodwill impairments in future years, if any, will depend on many sensitive, interrelated and uncertain variables including, among others, changing interest rates, utility sector market performance, ComEd’s capital structure,

market power prices, post-2006 rate regulatory structures, operating and capital expenditure requirements and other factors, some not yet known. See Critical Accounting Policies and Estimates for further discussion on goodwill impairments.

ComEd is and will continue to be involved in 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 or even reducing rates. 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 grants some certainty to all parties to the proceedings as to rates and energy costs.

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

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 ComEd’s maintenance and capital expenditures. ComEd cannot predict what impact these failures, or failures that impact other utilities such as the blackout in the Northeastern United States and Canada on August 14, 2003 (August Blackout), will have on its anticipated capital expenditures.

Although ComEd was not directly affected by the August Blackout, ComEd may be indirectly affected going forward. Regulated utilities that are required to provide service to all customers within their service territory have generally been afforded liability protections against claims by customers relating to failure of service. Following the August Blackout, significant claims have been asserted against various other utilities on behalf of both customers and non-customers for damages resulting from the blackout. ComEd cannot predict whether these claims will be upheld or whether they or legislative or regulatory initiatives in response to the August Blackout will change the traditional liability protections of utilities in providing regulated service. 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 has lost and may continue to lose energy customers to other generation suppliers, 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 may choose to purchase their generation supply from alternative electric generation suppliers. ComEd is generally obligated to provide generation and delivery service to customers in their service territories at fixed rates, or in some instances, market-derived rates. In addition, customers who take service from an alternative generation supplier may later return to ComEd, provided, however, that under Illinois law ComEd’s obligation to provide generation may be eliminated over time if the ICC finds that competitive supply options are available to certain classes of customers. ComEd remains obligated to provide transmission and distribution service to all customers regardless of their generation suppliers. The number of customers taking service from 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 Illinois regulatory commission. To the extent that customers leave traditional bundled tariffs and select a different generation supplier, ComEd’s revenues are likely to decline, and ComEd anticipates its revenues and gross margins could vary from period to period.

ComEd continues to serve as the POLR for energy for all customers in its service territories.Since ComEd customers can “switch,” that is, within limits they can choose an alternative generation supplier and then return to ComEd and then go back to an alternative supplier, and so on, planning for ComEd has a higher level of uncertainty than that traditionally experienced due to weather and the economy. ComEd has no obligation to purchase power reserves to cover the load served by others. ComEd manages its POLR obligation through full-requirements contracts with Generation, under which Generation supplies ComEd’s power requirements. Because of the ability of customers to switch generation suppliers, there is uncertainty regarding the amount of ComEd load for which Generation must prepare. This uncertainty increases Generation’s costs and may limit Generation’s sales opportunities.

ComEd has received ICC approval to phase out its obligation to provide fixed-price energy under bundled rates to approximately 350 of its largest energy customers, which ComEd believes partially mitigates its risk. These are commercial and industrial customers, including heavy industrial plants, large office buildings, government facilities and a variety of other businesses with demands of at least three MWs representing an aggregate of approximately 2,500 MWs of load. These customers accounted for 10% of ComEd’s 2003 MWh deliveries.

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 its transmission and distribution systems, resulting in increased maintenance costs and limiting its ability to meet peak customer demand. These extreme conditions may have detrimental effects on its operations.

Economic conditions and activity in ComEd’s service territories directly affect the demand for electricity.

Higher levels of development and business activity generally increase the number of customers and their average use of energy. Periods of recessionary economic conditions generally adversely affect ComEd’s results of operations. In the near term, retail sales growth on an annual basis is expected to be 1.2% in the service territory. Long-term retail sales growth for electricity is expected to be 1.5% per year for ComEd.

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, the August Blackout and the 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 Platform.The FERC has required jurisdictional utilities to provide open access to their transmission systems. It has also sought the voluntary development of regional transmission organizations (RTOs) and the elimination of trade barriers between regions. The FERC also proposed rulemakings to implement protocols to create a standard wholesale market platform for the wholesale markets for energy and capacity. The RTO would become the provider of the transmission service, and the transmission owners would recover their revenue requirements through it. The transmission owners would remain responsible for maintaining and physically operating their transmission facilities. The wholesale market

platform 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 manage congestion on transmission lines preferably by means of a financially based system known as “locational marginal pricing.” The FERC is likely to finalize its wholesale market platform rule during 2004.

ComEd and other Midwestern utilities are seeking to become fully integrated into the PJM RTO in 2004. When ComEd integrates into PJM, ComEd will recover its current transmission revenues through the PJM open-access transmission tariff (OATT), instead of ComEd’s own OATT.

The FERC’s RTO and standard market platform initiatives have generated substantial opposition by some state regulators and other governmental bodies. Efforts to develop an RTO have been abandoned in certain regions. ComEd supports both of these FERC initiatives but cannot predict whether they will be successful, what impact they may ultimately have on its 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 that ComEd has POLR obligations and may at some point no longer have long-term supply contracts with Generation or other suppliers for their loads, the ability of ComEd to cost effectively serve its POLR load obligations may depend on successful spot markets in its franchised service territories.

Proposed Federal Energy Legislation.One of the principal legislative initiatives of the Bush administration is the adoption of comprehensive federal energy legislation. In 2003, an energy bill was passed by the U.S. House of Representatives but was not voted on by the U.S. Senate. The energy bill, as currently written, would repeal the Public Utility Holding Company Act of 1935 (PUHCA), create incentives for the construction of transmission infrastructure, encourage but not mandate standardized competitive markets and expand the authority of the FERC to include overseeing the reliability of the bulk power system. ComEd cannot predict whether comprehensive energy legislation will be adopted and, if adopted, the final form of that legislation. ComEd would expect that comprehensive energy legislation would, if adopted, significantly affect the electric utility industry and ComEd’s businesses.

Capital Markets and Financing Environment

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

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

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

•

credit availability from banks and other financial institutions,

•

maintenance of acceptable credit ratings (see credit ratings in the credit issues section of Liquidity and Capital Resources above),

•

investor confidence in ComEd and Exelon,

•

general economic and capital market conditions,

•

the success of current projects, and

•

the perceived quality of new projects.

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

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

Market performance affects Exelon’s benefit plan asset values.

The performance of the capital markets affects the values of the assets that are held in trust to satisfy the future obligations under Exelon’s pension and postretirement benefit plans, in which ComEd participates. ComEd has significant obligations in these areas and Exelon holds significant assets in these trusts to meet these obligations. A decline in the market value of those assets, as was experienced from 2000 to 2002, may increase Exelon’s funding requirements for these obligations. ComEd may be required to fund a portion of these increased funding requirements.

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 that ComEd operates under and price pressures due to competition, ComEd may not be able to pass the costs of inflation through to customers.

Other

ComEd’s financial performance will be affected by its ability to achieve the targeted cash savings under Exelon’s new Exelon Way business model.

ComEd has begun to implement Exelon’s new Exelon Way business model, which is focused on improving operating cash flows while meeting service and financial commitments through improved integration of operations and consolidation of support functions. Exelon’s targeted annual cash savings range from approximately $300 million in 2004 to approximately $600 million in 2006. Exelon has incurred expenses, including employee severance costs, associated with reaching these annual cash savings levels and is considering whether there are additional expenses to be recorded in future periods. Exelon’s targeted annual cash savings do not reflect any expenses that may be incurred in future periods. Exelon’s inability to realize these annual cash savings levels in the targeted timeframes could adversely affect future financial performance.

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, site remediation and clean-up. Remediation activities associated with manufactured gas plant operations conducted by predecessor companies will be one component 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, 2003, ComEd’s reserve for environmental investigation and remediation costs was $69 million. ComEd has accrued and will continue to accrue amounts that management believes are prudent to cover these environmental liabilities, but ComEd cannot predict with any certainty whether these amounts will be sufficient to cover ComEd’s environmental liabilities. Management cannot predict whether ComEd will incur other significant liabilities for any additional investigation and remediation costs at additional sites not currently identified by ComEd, environmental agencies or others, or whether such costs will be recoverable from third parties.

ComEd’s financial performance is affected by increasing costs associated with additional security measures and obtaining adequate liability insurance.

Security.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, the FERC issued 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 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 terrorist acts may be limited. Exelon is self-insured to the extent that any losses may exceed the amount of insurance maintained.

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 generating 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 Note 1 of the Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.

PECO

Executive Summary

2003 has been a year of operating accomplishments. PECO has focused on living up to its reliability and safety commitments while pursuing greater productivity, quality and innovation. Here are just a few of the 2003 highlights:

Financial Results.PECO experienced an overall decline in net income of 2% in 2003. This decline was primarily due to higher fuel and operating and maintenance expenses, including costs associated with implementing The Exelon Way, and depreciation and amortization expense. PECO’s 2003 results were favorably affected by higher gas revenue, lower taxes other than income and lower interest expenses.

The Exelon Way.PECO implemented The Exelon Way, an aggressive, long-term operational plan defining how PECO will conduct business in years to come. The Exelon Way is focused on improving operating cash flows while meeting service and financial commitments through improved integration of operations and consolidation of support functions. Exelon’s targeted annual cash savings range from approximately $300 million in 2004 to approximately $600 million in 2006. PECO recorded severance and severance-related after-tax charges during 2003 associated with the implementation of The Exelon Way and is considering whether it will incur additional severance related costs in future periods.

Investment Strategy. PECO continued to invest in its infrastructure, spending over $250 million in 2003, and expects to invest $239 million in 2004.

Financing Activities. PECO refinanced or repaid $579 million of outstanding debt and equity securities in 2003 and repaid approximately $239 million of transition bonds and $154 million of commercial paper, resulting in annual interest savings of $38 million. PECO met all of its capital resource commitments with internally generated cash and expects to do so in the foreseeable future.

Operational Achievements. PECO’s business focused on the core fundamentals of providing reliable delivery service. PECO, and Exelon’s other operating affiliates combined resources to minimize the aftermath of Hurricane Isabel that affected the Philadelphia area and helped to prevent the potentially detrimental cascading effects of the August 14, 2003 blackout in the Northeastern United States and Canada (August Blackout) to its system and to its customers. Following several years of continued reliability improvement, PECO’s performance dipped slightly in 2003 due to Hurricane Isabel.

Outlook for 2004 and Beyond.In the short term, PECO’s financial results will be affected by weather conditions and the successful implementation of The Exelon Way. If weather is warmer than normal in the summer months or colder than normal in the winter months, operating revenues at PECO generally will be favorably affected.

Longer term, restructuring in the U.S. electric industry is at a crossroads at both the Federal and state levels, with continuing debate at the FERC on regional transmission organization (RTO) and standard market platform issues and in many states on the “post transition” format. Some states abandoned failed transition plans (like California), some states are adjusting current transition plans (like New Jersey and Ohio), and the state of Pennsylvania (by 2011) is considering options to preserve choice for large customers and rate stability for mass market customers, while ensuring the financial returns needed for continuing investments in reliability. PECO will continue to be an active participant in these policy debates, while continuing to focus on improving operations and controlling costs.

As PECO nears the end of the restructuring transition period for which its transmission and distribution rates are capped in Pennsylvania (2006), PECO will also continue to work with Federal and state regulators, state and local government, customer representatives and other interested parties to develop appropriate processes for establishing future rates in restructured electricity markets. As in the past, by working together with all interested

parties, PECO can successfully meet these objectives and obtain fair recovery of its costs for providing service to its customers. However, if PECO is unsuccessful, its results of operations and cash flows could be negatively affected.

While the U.S. economic recovery appears underway, PECO’s current plan is based on moderate sales growth (1% to 2%). Successful implementation of The Exelon Way is needed to offset labor and material cost escalation, especially the double digit increases in health care costs. PECO’s stable base of 1.5 million electric and 460, 000 gas customers will provide a solid platform with which to meet these challenges.

Results of Operations

Year Ended December 31, 2003 Compared To Year Ended December 31, 2002

Significant Operating Trends – PECO


	2003			2002			Variance			% Change
OPERATING REVENUES	$	4,388		$	4,333		$	55		1.3	%

OPERATING EXPENSES
Purchased power		1,677			1,669			8		0.5	%
Fuel		419			348			71		20.4	%
Operating and maintenance		576			523			53		10.1	%
Depreciation and amortization		487			456			31		6.8	%
Taxes other than income		173			244			(71	)	(29.1	)%

Total operating expense		3,332			3,240			92		2.8	%

OPERATING INCOME		1,056			1,093			(37	)	(3.4	)%

OTHER INCOME AND DEDUCTIONS
Interest expense		(324	)		(370	)		46		(12.4	)%
Distributions on mandatorily redeemable preferred securities		(8	)		(10	)		2		(20.0	)%
Other, net		2			32			(30	)	(93.8	)%

Total other income and deductions		(330	)		(348	)		18		(5.2	)%

INCOME BEFORE INCOME TAXES		726			745			(19	)	(2.6	)%

INCOME TAXES		253			259			(6	)	(2.3	)%

NET INCOME		473			486			(13	)	(2.7	)%
Preferred stock dividends		5			8			(3	)	(37.5	)%

NET INCOME ON COMMON STOCK	$	468		$	478		$	(10	)	(2.1	)%

Net Income

The decrease in net income in 2003 was a result of higher fuel, operating and maintenance and depreciation and amortization expense, partially offset by higher gas revenue, lower taxes other than income and lower interest expense.

Operating Revenue

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


Retail Deliveries – (in gigawatthours (GWhs))	2003	2002	Variance		% Change
Bundled deliveries (1)
Residential	11,358	10,365	993		9.6	%
Small commercial & industrial	6,624	7,606	(982	)	(12.9	)%
Large commercial & industrial	14,739	14,766	(27	)	(0.2	)%
Public authorities & electric railroads	897	852	45		5.3	%

	33,618	33,589	29		0.1	%

Unbundled deliveries (2)
Residential	900	1,971	(1,071	)	(54.3	)%
Small commercial & industrial	1,455	415	1,040		n.m.
Large commercial & industrial	780	557	223		40.0	%

	3,135	2,943	192		6.5	%

Total retail deliveries	36,753	36,532	221		0.6	%

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

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

n.m.	- not meaningful


Electric Revenue	2003		2002		Variance			% Change
Bundled revenue (1)
Residential	$	1,444	$	1,338	$	106		7.9	%
Small commercial & industrial		753		865		(112	)	(12.9	)%
Large commercial & industrial		1,090		1,086		4		0.4	%
Public authorities & electric railroads		80		79		1		1.3	%

		3,367		3,368		(1	)	n.m.

Unbundled revenue (2)
Residential		65		145		(80	)	(55.2	)%
Small commercial & industrial		75		21		54		n.m.
Large commercial & industrial		21		16		5		31.3	%

		161		182		(21	)	(11.5	)%

Total electric retail revenues		3,528		3,550		(22	)	(0.6	)%
Wholesale and miscellaneous revenue (3)		215		234		(19	)	(8.1	)%

Total electric revenue	$	3,743	$	3,784	$	(41	)	(1.1	)%

(1)	Bundled revenue reflects revenue from customers taking electric service under tariffed rates, which includes the cost of energy, the delivery cost of the transmission and the distribution of the energy and a CTC charge.

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

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

The changes in electric retail revenues in 2003, as compared to 2002, were attributable to the following:


	Variance
Rate mix	$	(25	)
Customer choice		(12	)
Volume		13
Weather		3
Other effects		(1	)

Electric retail revenue	$	(22	)

Rate Mix. The decrease in revenues from rate mix is due to changes in monthly usage patterns in all customer classes during 2003 compared to 2002.

Customer Choice. All PECO customers have the choice to purchase energy from alternative electric generation suppliers. This choice generally does not impact kWh deliveries, but reduces revenue collected from customers because they are not obtaining generation supply from PECO.

For the year ended December 31, 2003, the energy provided by alternative electric generation suppliers was 3,135 GWhs or 8.5% as compared to 2,943 GWhs or 8.0% for the year ended December 31, 2002. As of December 31, 2003, the number of customers served by alternative electric generation suppliers was 312,600 or 20.4% as compared to 277,800 or 18.2% as of December 31, 2002. The decrease in electric retail revenue associated with customer choice primarily relates to small commercial and industrial customers selecting or being assigned to alternative electric generation suppliers.

Volume. Exclusive of weather impacts, higher delivery volume increased PECO’s revenue $13 million compared to 2002, primarily related to increases in the residential customer class, reflecting customer growth, and increased usage in the small commercial and industrial customer classes.

Weather.The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity. Conversely, mild weather reduces demand. The weather impact was slightly favorable compared to the prior year reflecting colder winter weather during the beginning of the year, largely offset by cooler summer weather and warmer winter weather during the end of the year. Heating degree days increased 16% in 2003 compared to 2002. Cooling degree days decreased 21% compared to 2002.

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


Deliveries to customers (in million cubic feet (mmcf))	2003		2002		Variance			% Change
Retail sales		61,858		54,782		7,076		12.9	%
Transportation		26,404		30,763		(4,359	)	(14.2	)%

Total		88,262		85,545		2,717		3.2	%


Revenue	2003		2002		Variance			% Change
Retail sales	$	609	$	490	$	119		24.3	%
Transportation		18		19		(1	)	(5.3	)%
Resales and other		18		40		(22	)	(55.0	)%

Total	$	645	$	549	$	96		17.5	%

The changes in gas retail revenue for 2003, as compared to 2002, were attributable to the following:


	Variance
Weather	$	71
Rate changes		51
Volume		(3	)

Gas retail revenue	$	119

Weather.The weather impact was favorable in 2003 compared to 2002 reflecting colder winter weather during the beginning of the year, partly offset by warmer weather during the end of the year. Heating degree-days in PECO’s service territory increased 16% in 2003 compared to 2002.

Rate Changes.The favorable variance in rates was attributable to increases in rates through the purchased gas adjustment clause that became effective March 1, 2003, June 1, 2003 and December 1, 2003. The average purchased gas cost rate per mmcf for 2003 was 11% higher than the rate in 2002. PECO’s purchased gas cost rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between the actual cost of purchased gas and the amount included in rates.

Lower gas resale and other revenues are attributable to a decrease in off-system sales, exchanges and capacity releases during 2003 compared to 2002.

Purchased Power

The increase in purchased power expense was attributable to $10 million for higher electric delivery volume and $7 million for higher prices, including higher PJM ancillary charges, partially offset by decreased purchases of $9 million primarily related to additional small commercial and industrial customers selecting or being assigned to alternative electric generation suppliers in 2003.

Fuel

The increase in fuel expense in 2003 was primarily attributable to a $55 million increase in purchased gas volumes to meet increased customer demand and a $39 million increase due to higher gas costs, partially offset by a $28 million decrease in fuel expense associated with lower resale sales.

Operating and Maintenance

The increase in O&M expense was primarily attributable to $30 million of severance and severance-related costs associated with The Exelon Way, $22 million of higher storm-related costs, $16 million of increased employee fringe benefits, $7 million related to additional uncollectible accounts expense, partially offset by $13 million of lower costs associated with the initial implementation of automated meter reading services in 2002, and $15 million of lower payroll expense due to a lower number of employees. During 2002, PECO decreased its reserve for uncollectible accounts by $17 million as a result of a change in estimate.

Depreciation and Amortization

Depreciation and amortization expense in 2003 increased as compared to 2002 as follows:


	2003		2002		Variance			% Change
Competitive transition charge amortization	$	336	$	308	$	28		9.1	%
Depreciation expense		130		125		5		4.0	%
Other amortization expense		21		23		(2	)	(8.7	)%

Total depreciation and amortization	$	487	$	456	$	31		6.8	%

The additional amortization of the CTC is in accordance with PECO’s original settlement under the Pennsylvania Competition Act. The increase in depreciation expense was due to additional plant in service.

Taxes Other Than Income

The decrease in taxes other than income in 2003 was primarily attributable to a $58 million reversal of real estate tax accruals in 2003, a $16 million decrease in real estate tax expense in 2003, a $12 million reversal of the use tax accrual due to an audit settlement, partially offset by a $14 million reversal of an overaccrual of Pennsylvania sales and use tax in 2002.

Interest Charges

Interest charges consisted of interest expense, interest expense to unconsolidated affiliates and distributions on Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMPrS). The decrease in 2003 was primarily attributable to lower interest expense on long-term debt of $38 million as a result of less outstanding debt and refinancing of existing debt at lower interest rates, and the reversal of accrued interest expense on federal income taxes of $8 million in 2003.

Other Income and Deductions

The decrease in other income and deductions was primarily attributable to a reversal of interest expense on federal income taxes of $14 million and an $18 million IRS refund, both of which occurred during 2002.

Results of Operations

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

Significant Operating Trends – PECO


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

OPERATING EXPENSES
Purchased power		1,669			1,352			317		23.4	%
Fuel		348			450			(102	)	(22.7	)%
Operating and maintenance		523			587			(64	)	(10.9	)%
Depreciation and amortization		456			416			40		9.6	%
Taxes other than income		244			161			83		51.6	%

Total operating expense		3,240			2,966			274		9.2	%

OPERATING INCOME		1,093			999			94		9.4	%

OTHER INCOME AND DEDUCTIONS
Interest expense		(370	)		(413	)		43		(10.4	)%
Distributions on mandatorily redeemable preferred securities		(10	)		(10	)		—		—
Other, net		32			46			(14	)	(30.4	)%

Total other income and deductions		(348	)		(377	)		29		(7.7	)%

INCOME BEFORE INCOME TAXES		745			622			123		19.8	%

INCOME TAXES		259			197			62		31.5	%

NET INCOME		486			425			61		14.4	%
Preferred stock dividends		8			10			(2	)	(20.0	)%

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

Net Income

The increase in net income in 2002 was a result of higher sales volume, favorable rate adjustments, lower operating and maintenance expense and lower interest expense on debt partially offset by increased taxes other than income and increased depreciation and amortization expense.

Operating Revenue

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


Retail Deliveries – (in GWhs)	2002	2001	Variance		% Change
Bundled deliveries (1)
Residential	10,365	8,073	2,292		28.4	%
Small commercial & industrial	7,606	5,998	1,608		26.8	%
Large commercial & industrial	14,766	12,960	1,806		13.9	%
Public authorities & electric railroads	852	765	87		11.4	%

	33,589	27,796	5,793		20.8	%

Unbundled deliveries (2)
Residential	1,971	3,105	(1,134	)	(36.5	)%
Small commercial & industrial	415	1,606	(1,191	)	(74.2	)%
Large commercial & industrial	557	2,352	(1,795	)	(76.3	)%
Public authorities & electric railroads	—	7	(7	)	(100.0	)%

	2,943	7,070	(4,127	)	(58.4	)%

Total retail deliveries	36,532	34,866	1,666		4.8	%

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

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


Electric Revenue	2002		2001		Variance			% Change
Bundled revenue (1)
Residential	$	1,338	$	1,028	$	310		30.2	%
Small commercial & industrial		865		682		183		26.8	%
Large commercial & industrial		1,086		929		157		16.9	%
Public authorities & electric railroads		79		72		7		9.7	%

		3,368		2,711		657		24.2	%

Unbundled revenue (2)
Residential		145		235		(90	)	(38.3	)%
Small commercial & industrial		21		81		(60	)	(74.1	)%
Large commercial & industrial		16		64		(48	)	(75.0	)%
Public authorities & electric railroads		—		1		(1	)	(100.0	)%

		182		381		(199	)	(52.2	)%

Total Electric Retail Revenues		3,550		3,092		458		14.8	%
Wholesale and miscellaneous revenue (3)		234		219		15		6.8	%

Total electric revenue	$	3,784	$	3,311	$	473		14.3	%

(1)	Bundled revenue reflects revenue from customers taking electric service under tariffed rates, which includes the cost of energy, the delivery cost of the transmission and the distribution of the energy and a CTC charge.

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

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

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


	Variance
Customer choice	$	226
Volume		133
Weather		63
Rate changes		45
Other effects		(9	)

Electric retail revenue	$	458

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

Volume. Exclusive of weather impacts, higher delivery volume increased PECO’s revenue $133 million compared to 2001, primarily related to increased usage in the residential and small commercial and industrial customer classes.

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

Rate Changes. The increase in revenues attributable to rate changes primarily reflects the expiration of a 6% reduction in PECO’s electric rates during the first quarter of 2001 and a $50 million increase as a result of the increase in the gross receipts tax rate effective January 1, 2002. These increases are partially offset by the timing of a $60 million rate reduction in effect for 2001 and 2002.

As permitted by the Pennsylvania Competition Act, the Pennsylvania Department of Revenue 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. 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.

Other Effects.Other items affecting revenue include an $11 million settlement of CTC’s by a large customer in the first quarter of 2001.

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


Deliveries to customers in mmcf	2002		2001		Variance			% Change
Retail sales		54,782		54,075		707		1.3	%
Transportation		30,763		27,453		3,310		12.1	%

Total		85,545		81,528		4,017		4.9	%


Revenue	2002		2001		Variance			% Change
Retail sales	$	490	$	581	$	(91	)	(15.7	)%
Transportation		19		18		1		5.6	%
Resales and other		40		55		(15	)	(27.3	)%

Total	$	549	$	654	$	(105	)	(16.1	)%

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


	Variance
Rate changes	$	(108	)
Weather		2
Volume		15

Gas retail revenue	$	(91	)

Rate Changes.The unfavorable variance in rates was primarily attributable to a decrease in rates through the purchased gas adjustment clause that became effective in December 2001. The average purchased gas cost rate per mmcf for 2002 was 22% lower than the rate in 2001.

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

Volume.Exclusive of weather impacts, higher delivery volume increased revenue by $15 million in 2002 compared to 2001. Total deliveries to customers increased 5% in 2002 compared to 2001, primarily as a result of customer growth and higher transportation volumes.

Lower gas resale and other revenues are attributable to a decrease in off-system sales, exchanges and capacity releases during 2002 compared to 2001.

Purchased Power

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

The decrease in fuel expense was primarily attributable to a $108 million decrease from lower gas prices.

Operating and Maintenance

The decrease in O&M expense in 2002 was primarily attributable to a $23 million reduction in the allowance for the uncollectible accounts during 2002, and $6 million related to lower corporate allocations. The

decrease is also attributable to $18 million of employee severance costs associated with the Merger, $12 million of incremental costs related to two storms, $7 million attributable to customer choice and $5 million associated with a write-off of excess and obsolete inventory, all of which occurred in 2001. These decreases are partially offset by $12 million related to additional costs associated with the deployment of automated meter reading technology during 2002.

Depreciation and Amortization

Depreciation and amortization expense in 2002 increased as compared to 2001 as follows:


	2002		2001		Variance			% Change
Competitive transition charge amortization	$	308	$	271	$	37		13.7	%
Depreciation expense		125		119		6		5.0	%
Other amortization expense		23		26		(3	)	(11.5	)%

Total depreciation and amortization	$	456	$	416	$	40		9.6	%

Taxes Other Than Income

The increase in taxes other than income in 2002 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 consisted of interest expense and distributions on COMPrS. The decrease in 2002 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

The decrease in other income and deductions in 2002 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.

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, participation in the intercompany money pool or capital contributions from Exelon. 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. If these conditions deteriorate to where PECO no longer has access to external financing sources at reasonable terms, PECO has access to a revolving credit facility that PECO currently utilizes to support its commercial paper program. See the Credit Issues section of Liquidity and Capital Resources for further discussion. Capital resources are used primarily to fund PECO’s capital requirements, including construction, repayments of maturing debt, the payment of dividends and contributions to Exelon’s pension plans.

As part of the implementation of The Exelon Way, PECO identified approximately 166 positions for elimination by the end of 2004 and recorded a charge for salary continuance severance of $16 million before income taxes during 2003, which PECO anticipates that the majority will be paid in 2004 and 2005. PECO is considering whether there are additional positions to be eliminated in 2005 and 2006. PECO may incur further severance-related costs associated with The Exelon Way if additional positions are identified to be eliminated. These costs will be recorded in the period in which the costs can be reasonably estimated.

Cash Flows from Operating Activities

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. Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flow, sufficient to meet operating and capital expenditures requirements for the foreseeable future. See Business Outlook and Challenges in Managing our Business.

Cash flows provided by operations for the years ended December 31, 2003 and 2002 were $814 million and $760 million, respectively. Changes in PECO’s cash flows from operations are generally consistent with changes in its results of operations, as further adjusted by changes in working capital in the normal course of business.

In addition to the items mentioned in Results of Operation, PECO’s operating cash flows in 2003 were affected by the following items:

•

Purchases of natural gas at higher prices as well as slightly increased volumes during 2003 resulted in an increase in natural gas inventories of $32 million from December 31, 2002 and an increase in deferred natural gas costs of $50 million, resulting in a decrease to operating cash flows of $82 million during 2003. During 2002, changes in deferred natural gas costs of $25 million and a decrease in inventories during the year of $5 million, resulted in a $30 million increase to operating cash flows.

•

Discretionary contributions to Exelon’s defined benefit pension plans of $18 million in 2003. PECO did not contribute to the pension plans in 2002.

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 expects to make a discretionary pension plan contribution up to approximately $419 million in 2004, of which, $8 million is expected to be funded by PECO.

Cash Flows from Investing Activities

Cash flows used in investing activities in 2003 were $246 million compared to $260 million in 2002. The decrease in cash flows used in investing activities was primarily attributable to a decrease in capital expenditures. PECO’s investing activities during 2003 were funded primarily by operating activities.

PECO’s projected capital expenditures for 2004 are $239 million. Approximately 60% of the budgeted 2004 expenditures are for additions to or upgrades of existing facilities, including reliability improvements. The remainder of the capital expenditures support customer and load growth. 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 2003 were $587 million compared to $469 million in 2002. Cash flows used in financing activities are primarily attributable to debt service and payment of dividends to Exelon. The increase in cash flows used in financing activities was primarily attributable to increased debt and preferred securities redemptions of $481 million, partially offset by additional issuances of long-term debt of $328 million. PECO paid a $322 million dividend to Exelon during 2003 compared to a $340 million dividend in 2002.

Credit Issues

Exelon Credit Facility.PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from Exelon’s intercompany money pool. In October 2003, Exelon, ComEd, PECO and Generation replaced their $1.5 billion bank unsecured revolving credit facility with a $750 million 364-day unsecured revolving credit agreement and a $750 million 3-year unsecured revolving credit agreement with a group of banks. Both revolving credit agreements are used principally to support the commercial paper programs at Exelon, ComEd, PECO and Generation and to issue letters of credit. The 364-day agreement also includes a term-out option provision that allows a borrower to extend the maturity of revolving credit borrowings outstanding at the end of the 364-day period for one year.

At December 31, 2003, PECO’s aggregate sublimit under the credit agreements was $150 million. Sublimits under the credit agreements can change upon written notification to the bank group. PECO had approximately $148 million of unused bank commitments under the credit agreements at December 31, 2003. At December 31, 2003, commercial paper outstanding was $46 million. Interest rates on the advances under the credit facility are based on either the London Interbank Offering Rate (LIBOR) or prime plus an adder based on the credit rating of the borrower as well as the total outstanding amounts under the agreement at the time of borrowing. The maximum adder would be 175 basis points.

For 2003, the average interest rate on notes payable was approximately 1.23%. 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, 2003. At December 31, 2003, PECO was in compliance with the credit agreement thresholds.

Capital Structure.At December 31, 2003, PECO’s capital structure consisted of 14% common equity, 1% notes payable, 1% preferred securities, and 84% long-term debt, including long-term debt to unconsolidated affiliates. Long-term debt included $4.0 billion of long-term debt to an unconsolidated affiliate, PECO Energy Transition Trust, which issued transition bonds representing 62% of capitalization. PECO’s capital structure, excluding the deduction from shareholders’ equity of the $1.6 billion receivable from Exelon (which amount is deducted for GAAP purposes but is excluded here to reflect amounts expected to be received by PECO from Exelon to pay future taxes), consisted of 31% common equity, 1% notes payable, 1% preferred securities, and 67% long-term debt, including long-term debt to unconsolidated affiliates.

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 Corporate may participate as a lender. Funding of, and borrowings from, the money pool are predicated on whether the contributions and borrowings result in economic benefits. Interest on borrowings is based on short-term market rates of interest, or, if from an external source, specific borrowing rates. PECO had no borrowings from the money pool during 2003. During 2003, PECO had various investments in the money pool. The maximum amount of PECO’s investment at any time during 2003 was $59 million. At December 31, 2003, PECO had no amounts invested in the intercompany money pool. During 2003, PECO earned less than $1 million in interest from its investments in the intercompany money pool.

Security Ratings.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. In the fourth quarter of 2003, Standard & Poor’s Ratings Services affirmed PECO’s corporate credit ratings but revised its outlook to negative from stable. None of PECO’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. The following table shows PECO’s securities ratings at December 31, 2003:


Securities	Moody’s Investors Service	Standard & Poor’s	Fitch Ratings
Senior secured debt	A2	A	A
Transition bonds (1)	Aaa	AAA	AAA
Commercial paper	P1	A2	F1

(1)	Issued by PECO Energy Transition Trust, an unconsolidated affiliate of PECO.

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.

Fund Transfer Restrictions.Under applicable law, 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, 2003, PECO had retained earnings of $546 million.

Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations

PECO’s contractual obligations as of December 31, 2003 representing cash obligations that are considered to be firm commitments are as follows:


			Payment due within						Due after 5 Years
(in millions)	Total		1 Year		2-3 Years		4-5 Years		Due after 5 Years
Long-term debt	$	1,361	$	—	$	124	$	452	$	785
Long-term debt to affiliates		4,033		153		949		1,270		1,661
Notes payable		46		46		—		—		—
Operating leases		14		4		6		2		2

Total contractual obligations	$	5,454	$	203	$	1,079	$	1,724	$	2,448

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

•

long-term debt, including long-term debt due to affiliates, see Note 7

•

notes payable, see Note 6

•

operating leases, see Note 14

See Note 14 to the Notes to Consolidated Financial Statements for discussion of PECO’s commercial commitments as of December 31, 2003.

Accounts Receivable Agreement.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, 2003, PECO had sold a $225 million interest in accounts receivable, consisting of a $176 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 $49 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 3 of the Notes to Consolidated Financial Statements. PECO must continue to service these receivables and must maintain the level of the accounts receivable at $225 million. If PECO fails to maintain that level, the cash that would otherwise be received by PECO under this program must be held in escrow until the level is met. At December 31, 2003 and 2002, PECO met this requirement and was not required to make any cash deposits.

IRS Refund Claims

PECO entered into several agreements with a tax consultant related to the filing of refund claims with the Internal Revenue Service (IRS) and have made refundable prepayments of $5 million for potential fees associated with these agreements. The fees for these agreements are contingent upon a successful outcome and are based upon a percentage of the refunds recovered from the IRS, if any. As such, ultimate net cash flows to PECO related to these agreements will either be positive or neutral depending upon the outcome of the refund claim with the IRS. These potential tax benefits and associated fees could be material to PECO’s financial position, results of operations and cash flows. PECO cannot predict the timing of the final resolution of these refund claims.

Financing Trusts of ComEd and PECO. During June 2003, PECO issued $103 million of subordinated debentures to PECO Energy Capital Trust IV (PECO Trust IV) in connection with the issuance by PECO Trust IV of $100 million of preferred securities (see Note 16 of the Notes to Consolidated Financial Statements). Effective July 1, 2003, PECO Trust IV was deconsolidated from the financial statements of PECO in conjunction with FIN No. 46. The $103 million of subordinated debentures issued by PECO to PECO Trust IV was recorded as long-term debt to financing trusts within the Consolidated Balance Sheets.

Critical Accounting Policies and Estimates

See ComEd, PECO and Generation – Critical Accounting Policies and Estimates above for a discussion of PECO’s critical accounting policies and estimates.

Business Outlook and the Challenges in Managing Our Business

PECO’s business is comprised of utility transmission and distribution operations, which provides electricity and natural gas to customers in Pennsylvania. The electric industry in the United States is in the midst of a fundamental and, at this point, uncertain transition from a fully regulated industry offering bundled service to an industry with unbundled services, some of which are regulated and others of which are priced in competitive markets. PECO’s energy delivery business remains highly regulated and is capital intensive.

The challenges affecting PECO’s businesses are discussed below. Further discussion of PECO’s liquidity position and capital resources and related challenges is included in the Liquidity and Capital Resources section.

Pennsylvania has restructuring legislation, the Pennsylvania Electric Generation Customer Choice and Competition Act (Competition Act), designed to foster competition in the retail sale of electricity. As a result, PECO is subject to rate caps for each of the transmission, distribution and energy components of its electric

service rates, through mandated restructuring transition periods as described below. During these periods, PECO’s results of operations will depend on its ability to deliver energy in a cost-efficient manner and to offset infrastructure investments and inflation with cost savings initiatives. PECO has long-term, full-requirements supply contracts with Generation, helping to mitigate the risk of changing energy supply costs through December 31, 2010. PECO is also managing operations and maintenance costs by implementing The Exelon Way business model, while maintaining a focus on both reliability and safety in operating the business.

PECO cannot currently predict the framework that will be used by the Pennsylvania state regulators to establish rates after the transition periods. PECO also cannot predict the outcome of any new laws that may impact its business. PECO may retain significant POLR obligations which require PECO to provide service to customers in its service area. PECO therefore must continue to ensure adequate supplies of electricity and gas are available at reasonable costs. While PECO does not have its own generation capabilities, PECO believes its ongoing relationship with Generation will serve to lessen the supply and price risks associated with its expected ongoing power procurement responsibilities.

More detailed explanations for each of these and other challenges in managing the business are as follows:

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

PECO’s business 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 the utilities and its affiliates. PECO is also subject to regulation by the FERC, which regulates transmission rates, gas pipelines and certain other aspects of the business. 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 operations and the level of rates that may be charged to recover such costs.

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

Electricity rate caps in effect at PECO currently limit the ability to recover increased expenses and the costs of investments in new transmission and distribution facilities. As a result, PECO’s future results of operations will depend on the ability to deliver electricity, in a cost-efficient manner and to realize cost savings under The Exelon Way to offset increased infrastructure investments and inflation.

Rate limitations.PECO is subject to agreed-upon rate reductions of $200 million, in aggregate, for the period 2002 through 2005, including $80 million, in aggregate, for the years 2004 and 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, and on its energy rates through December 31, 2010, as a result of settlements previously reached with the PUC.

PECO’s long-term purchased power agreement provides a hedge to its customers’ demand.

To effectively manage its obligation to provide power to meet its customers’ demand, PECO has established a full-requirements, power supply agreement with Generation which reduces PECO’s exposure to the volatility of customer demand and market prices through 2010. Under this agreement, PECO remits to Generation the amounts collected from customers for the energy component of rates, net of gross receipts taxes and ancillary charges. Market prices relative to PECO’s regulated rates still influence switching behavior among retail customers.

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 expects to continue 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 further expects those capital expenditures will exceed depreciation on its plant assets. PECO’s transmission and distribution rate cap will generally preclude incremental rate recovery on any of these incremental investments prior to January 1, 2007.

PECO’s business may be significantly affected by the end of the Pennsylvania regulatory transition period.

In Pennsylvania, the Competition Act provides for the imposition and collection of non-bypassable CTCs on customers’ bills as a mechanism for utilities to recover their allowed stranded costs. CTCs are assessed to and collected from all retail customers who have been assigned stranded cost responsibility and access the utilities’ transmission and distribution systems. As the CTCs are based on access to the utility’s transmission and distribution system, they will be assessed regardless of whether such customer purchases electricity from the utility or an 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 were awarded, except where continued operation is no longer cost efficient because of the transition to a competitive market.

PECO has been authorized by the PUC to recover stranded costs of $5.3 billion over a twelve-year period ending December 31, 2010, with a return on the unamortized balance of 10.75%. At December 31, 2003, approximately $4.3 billion remain to be recovered. Recovery of transition charges for stranded costs and PECO’s allowed return on its recovery of stranded costs are included in revenues. Amortization of PECO’s stranded cost recovery, which is a regulatory asset, is included in depreciation and amortization expense. PECO’s results will be adversely affected over the remaining period ending December 31, 2010 by the steadily increasing amortization of stranded costs. The following table (amounts in millions) indicates the estimated revenues and amortization expense associated with CTC collection and stranded cost recovery through 2010.


Year	Estimated CTC Revenue		Estimated Stranded Cost Amortization
2004	$	812	$	367
2005		808		404
2006		903		550
2007		910		619
2008		917		697
2009		924		783
2010		932		879

By the end of 2010, PECO will have fully recovered all of the stranded costs authorized by the PUC. As a result, PECO expects that both its revenues and expenses will decrease in 2011. The end of the transition period involves uncertainties, including the nature of PECO’s POLR obligations and the source and pricing of generation services to be provided by PECO. PECO expects to pursue resolution of these uncertainties during the remaining transition period.

PECO is and will continue to be involved in 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 or even reducing rates. 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 grants some certainty to all parties to the proceedings as to rates and energy costs.

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

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 cannot predict what impact these failures, or failures that impact other utilities such as the blackout in the Northeastern United States and Canada on August 14, 2003 (August Blackout), will have on its anticipated capital expenditures.

Although PECO was not directly affected by the August Blackout, PECO may be indirectly affected going forward. Regulated utilities that are required to provide service to all customers within their service territory have generally been afforded liability protections against claims by customers relating to failure of service. Following the August Blackout, significant claims have been asserted against various other utilities on behalf of both customers and non-customers for damages resulting from the blackout. PECO cannot predict whether these claims will be upheld or whether they or legislative or regulatory initiatives in response to the August Blackout will change the traditional liability protections of utilities in providing regulated service.

PECO has lost and may continue to lose electric energy customers to other generation suppliers, 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 electric generation suppliers.As a result of restructuring initiatives in Pennsylvania, all of PECO’s retail electric customers may choose to purchase their generation supply from alternative electric generation suppliers. In addition, since MST requirements for customers taking service from alternative generation suppliers agreed to by PECO were not met, PECO has been required to assign both commercial and residential customers to alternative generation suppliers. In addition, customers who take service from 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. The number of customers taking service from 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. To the extent that customers leave traditional bundled tariffs and select a different generation supplier, PECO’s revenues are likely to decline and revenues and gross margins could vary from period to period.

PECO continues to serve as POLR for electric energy for all customers in its service territories.Since PECO customers can “switch,” that is, within limits they can choose an alternative generation supplier and then return to PECO and then go back to an alternative supplier, and so on, planning for PECO has a higher level of uncertainty than that traditionally experienced due to weather and the economy. PECO has no obligation to purchase power reserves to cover the load served by others. PECO manages its POLR obligation through full-requirements contracts 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. This uncertainty increases Generation’s costs and may limit Generation’s sales opportunities.

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 differentials, coupled with higher consumption levels, PECO typically reports higher revenues in the third quarter of its fiscal year. However, extreme summer conditions or storms may stress its transmission and distribution system, resulting in increased

maintenance costs and limiting its ability to meet peak customer demand. These extreme conditions may have detrimental effects on its operations.

Economic conditions and activity in PECO’s service territories directly affect the demand for electricity and gas.

Higher levels of development and business activity generally increase the number of customers and their average use of energy. Periods of recessionary economic conditions generally adversely affect PECO’s results of operations. Sales growth from 2003 to 2004 on an annual basis is expected to be 1.3% in the service territory of PECO. Long-term retail sales growth for electricity is expected to be 1.0% per year for PECO.

PECO’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, the August Blackout and the publicized problems of some energy companies. Pennsylvania has adopted restructuring legislation designed to foster competition in the retail sale of electricity.

PECO is a member of PJM Interconnection, LLC (PJM), an approved RTO operating in the Mid-Atlantic region.

The FERC’s RTO and standard market platform initiatives have generated substantial opposition by some state regulators and other governmental bodies. Efforts to develop an RTO have been abandoned in certain regions. PECO supports both of these FERC initiatives but cannot predict whether they will be successful, what impact they may ultimately have on its 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 that PECO has POLR obligations and may at some point no longer have long-term supply contracts with Generation for their loads, the ability of PECO to cost effectively serve its POLR load obligations may depend on the continued operation of the PJM spot markets.

One of the principal legislative initiatives of the Bush administration is the adoption of comprehensive federal energy legislation. In 2003, an energy bill was passed by the U.S. House of Representatives but was not voted on by the U.S. Senate. The energy bill, as currently written, would repeal the Public Utility Holding Company Act of 1935 (PUHCA), create incentives for the construction of transmission infrastructure, encourage but not mandate standardized competitive markets and expand the authority of the FERC to include overseeing the reliability of the bulk power system. PECO cannot predict whether comprehensive energy legislation will be adopted and, if adopted, the final form of that legislation. PECO would expect that comprehensive energy legislation would, if adopted, significantly affect the electric utility industry and its businesses.

Capital Markets and Financing Environment

In order to expand PECO’s operations and to meet the needs of its current and future customers, PECO invests in its business. PECO’s ability to finance its business and other necessary expenditures is affected by the

capital intensive nature of its operations and PECO’s current and future credit ratings. The capital markets also affect Exelon’s benefit plan assets. Further discussions of PECO’s liquidity position can be found in the Liquidity and Capital Resources section above.

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

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

•

credit availability from banks and other financial institutions,

•

maintenance of acceptable credit ratings (see credit ratings in the credit issues section of Liquidity and Capital Resources above),

•

investor confidence in PECO and Exelon and,

•

general economic and capital market conditions.

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 cause PECO to incur higher financing costs.

Market performance affects Exelon’s benefit plan asset values.

The performance of the capital markets affects the values of the assets that are held in trust to satisfy the future obligations under Exelon’s pension and postretirement benefit plans, in which PECO participates. PECO has significant obligations in these areas and Exelon holds significant assets in these trusts to meet these obligations. A decline in the market value of those assets, as was experienced from 2000 to 2002, may increase Exelon’s funding requirements for these obligations. PECO may be required to fund a portion of these increased funding requirements.

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 transmission and distribution rate cap that PECO operates under, PECO is not able to pass the costs of inflation through to customers.

Other

PECO’s financial performance will be affected by its ability to achieve the targeted cash savings under Exelon’s new Exelon Way business model.

PECO has begun to implement Exelon’s new Exelon Way business model, which is focused on improving operating cash flows while meeting service and financial commitments through improved integration of operations and consolidation of support functions. Exelon’s targeted annual cash savings range from approximately $300 million in 2004 to approximately $600 million in 2006. Exelon has incurred expenses, including employee severance costs, associated with reaching these annual cash savings levels and is considering whether there are additional expenses to be recorded in future periods. Exelon’s targeted annual cash savings do

not reflect any expenses that may be incurred in future periods. Exelon’s inability to realize these annual cash savings levels in the targeted timeframes could adversely affect future financial performance.

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, site remediation and clean-up. Remediation activities associated with manufactured gas plant operations will be one component 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, 2003, PECO’s reserve for environmental investigation and remediation costs was $50 million. 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 currently is recovering through regulated gas rates costs associated with the remediation of MGP sites.

PECO’s financial performance is affected by increasing costs associated with additional security measures and obtaining adequate liability insurance.

Security.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, the FERC issued minimum standards to safeguard the electric grid system 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 terrorist acts, the available coverage and limits may be less than the amount of insurance obtained in the past, and the recovery for losses due to terrorists acts may be limited. PECO is self-insured to the extent that any losses may exceed the amount of insurance maintained.

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 generating 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 PECO’s results of operations or financial condition.

New Accounting Pronouncements

See Note 1 of the Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.

Generation

Executive Summary

2003 has been a year of operating accomplishments and painful investment write-offs. Generation has focused on living up to its commitments while pursuing greater productivity, quality and innovation.

Financial Results. Generation realized a net loss of $133 million in 2003, a decline of $533 million from 2002 primarily due to a charge of $573 million (after-tax) related to the impairment of the long-lived assets of Boston Generating, LLC (Boston Generating), formerly known as Exelon Boston Generating, LLC. In addition, Generation incurred impairment and transaction-related charges of $180 million (after-tax) related to its investment in Sithe and severance and severance-related charges associated with The Exelon Way. Generation’s 2003 results were favorably affected by modest improvements in wholesale energy prices, which increased its energy margins. Generation also recorded a one-time after-tax gain of $108 million upon the adoption of a new accounting standard that has a significant impact on how Generation accounts for its nuclear decommissioning obligation.

The Exelon Way.Generation implemented The Exelon Way, an aggressive plan defining how it will conduct business in years to come. The Exelon Way is focused on improving operating cash flows while meeting service and financial commitments through improved integration of operations and consolidation of support functions. Exelon’s targeted annual cash savings range from approximately $300 million in 2004 to approximately $600 million in 2006. In addition to the severance and severance-related charges Generation recorded during 2003, it may incur additional charges associated with The Exelon Way in future periods.

Investment Strategy. Generation continued to follow a disciplined approach to investing to maximize the earnings and cash flows from its assets and businesses and to sell those that do not meet its goals. Generation’s 2003 highlights include:

•

Generation announced its transition out of its ownership of Boston Generating in July 2003.

•

Generation completed a series of transactions in November 2003 that restructured the ownership of Sithe, with Generation continuing to own a 50% interest in Sithe. Generation continues to pursue the divestiture of its investment in Sithe.

Generation purchased British Energy plc’s 50% interest in AmerGen Energy Company, LLC (AmerGen) in December 2003. AmerGen, which owns the Clinton Power Station, Three Mile Island Nuclear Station Unit 1 and the Oyster Creek Generating Station representing about 2,500 megawatts of capacity, is now a wholly owned subsidiary.

Financing Activities. Generation issued $500 million of senior notes in 2003, and refinanced $17 million of outstanding pollution control bonds. Generation met all of its capital resource commitments with internally generated cash and expects to do so in the foreseeable future, absent new acquisitions.

Operational Achievements. Generation focused on the core fundamentals of providing efficient generation to its customers. Generation’s nuclear business combined with other Exelon businesses to minimize the aftermath of Hurricane Isabel and helped to prevent the potentially detrimental cascading effects of the August 14, 2003 blackout in the Northeastern United States and Canada. Also, Generation’s nuclear fleet achieved a 93.4% capacity factor in 2003 compared to 92.7% in 2002 while reducing the costs of nuclear generation to 1.25 cents per kilowatthour.

Outlook for 2004 and Beyond. In the short term, Generation’s financial results will be affected by a number of factors, including weather conditions, wholesale market prices, successful implementation of The Exelon Way and Generation’s ability to generate electricity at low costs. If weather is warmer than normal in the summer months or colder than normal in the winter months, demand for energy generally will be favorably affected. Operating revenues will also be favorably affected by increases in wholesale market prices. Generation’s

continued transition out of ownership at Boston Generating, and the successful integration of the AmerGen acquisition into its nuclear fleet will continue to enhance its operations and overall investment return.

Longer term, restructuring in the U.S. electric industry is at a crossroads at both the Federal and state levels, whether debating regional transmission organization (RTO) or standard market platform issues at the FERC or the “post transition” format in many states. Some states abandoned failed transition plans (like California), some states are adjusting current transition plans (like New Jersey and Ohio), and the states of Illinois (by 2007) and Pennsylvania (by 2011) are considering options to preserve choice for large customers and rate stability for mass market customers, while ensuring the financial returns needed for continuing investments in reliability. Generation will continue to be an active participant in these policy debates, while continuing to focus on improving operations, controlling costs and providing a fair return to its investors.

While U.S. economic recovery appears underway, Generation’s current plans are based on continued softness in wholesale power markets. Successful implementation of The Exelon Way is needed to offset labor and material cost escalation, especially the double digit increases in health care costs. Despite these challenges, Generation’s diverse mix of generation (nuclear, coal, purchased power, natural gas, hydroelectric, wind and other renewables) and its position as a low-cost producer linked to a stable base of Exelon Energy Delivery customers will provide a solid platform from which it will strive to meet these challenges.

Results of Operations

Year Ended December 31, 2003 Compared To Year Ended December 31, 2002

Significant Operating Trends – Generation


	2003			2002			Variance			% Change
OPERATING REVENUES	$	8,135		$	6,858		$	1,277		18.6	%

OPERATING EXPENSES
Purchased power		3,587			3,294			293		8.9	%
Fuel		1,533			959			574		59.9	%
Operating and maintenance		1,945			1,656			289		17.5	%
Impairment of Boston Generating, LLC long-lived assets		945			—			945		n.m.
Depreciation		199			276			(77	)	(27.9	)%
Taxes other than income		120			164			(44	)	(26.8	)%

Total operating expense		8,329			6,349			1,980		31.2	%

OPERATING INCOME (LOSS)		(194	)		509			(703	)	(138.1	)%

OTHER INCOME AND DEDUCTIONS
Interest expense		(88	)		(75	)		(13	)	17.3	%
Equity in earnings of unconsolidated affiliates		49			87			(38	)	(43.7	)%
Other, net		(187	)		83			(270	)	n.m.

Total other income and deductions		(226	)		95			(321	)	n.m.

INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES		(420	)		604			(1,024	)	(169.5	)%

INCOME TAXES		(179	)		217			(396	)	(182.5	)%

INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES		(241	)		387			(628	)	(162.3	)%

CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES, (net of income taxes)		108			13			95		n.m.

NET INCOME (LOSS)	$	(133	)	$	400		$	(533	)	(133.3	)%

n.m. not meaningful

Net Income

Net income was adversely affected by the after-tax impairment charges of $573 million relating to the long-lived assets of Boston Generating and $180 million relating to Generation’s investment in Sithe Energies. Net income was favorably affected by increased revenue net fuel attributable to higher prices and volumes of wholesale energy, and the impact of the Exelon New England acquisition in 2002, slightly offset by decreased sales to affiliates.

Operating Revenues

Operating revenues increased in 2003 as compared to 2002. Generation’s sales in 2003 and 2002 were as follows:


Revenue (in millions)	2003		2002			Variance			% Change
Energy Delivery and Exelon Energy Company	$	4,036	$	4,213		$	(177	)	(4.2	)%
Market sales		3,861		2,591			1,270		49.0	%

Total energy sales revenue		7,897		6,804			1,093		16.1	%
Trading portfolio		1		(29	)		30		(103.4	)%
Other revenue		237		83			154		185.5	%

Total revenue	$	8,135	$	6,858		$	1,277		18.6	%


Sales (in GWhs) (1)	2003		2002			Variance			% Change
Energy Delivery and Exelon Energy Company		117,405		123,975			(6,570	)	(5.3	)%
Market sales		107,267		83,565			23,702		28.4	%

Total sales		224,672		207,540			17,132		8.3	%

(1)	One GWh is the equivalent of one million kWhs.

Trading volumes of 32,584 GWhs and 69,933 GWhs for the years ended December 31, 2003 and 2002, respectively, are not included in the table above. The decrease in trading volume is a result of reduced volumetric and VAR trading limits in 2003, which are set by the Exelon Risk Management Committee and approved by the Board of Directors.

Generation’s average revenues per MWh sold for the years ended December 31, 2003 and 2002 were as follows:


($/MWh)	2003		2002		% Change
Average revenue
Energy Delivery and Exelon Energy Company	$	34.38	$	33.98	1.2	%
Market sales		35.99		31.01	16.1	%
Total - excluding the trading portfolio		35.15		32.78	7.2	%

Exelon Delivery and Exelon Energy Company. Sales to affiliates decreased primarily due to lower volume sales to ComEd, offset by slightly higher prices. Revenues from PECO were lower, primarily due to lower prices, offset slightly by higher volumes. Sales to Exelon Energy Company decreased primarily due to the discontinuance of Exelon Energy Company operations in the PJM region. Effective January 1, 2004, Exelon Energy Company’s competitive retail sales business became part of Generation.

Market Sales. Revenue from market sales increased due primarily to higher market prices and the realization of the effects of the Exelon New England acquisition.

Trading Revenues. Trading margin increased, reflecting a $1 million gain for the year ended December 31, 2003 as compared to a $29 million loss in the same period in 2002. The increase is primarily related to an increase in gas prices in April 2002, which negatively affected Generation’s trading positions.

Other Revenue.Revenues also increased in 2003 as compared to 2002, as a result of a $76 million increase in sales of excess fossil fuel. The excess fossil fuel is a result of generating plants in Texas and New England operating at less than projected levels. Also, revenues increased by $62 million due to higher decommissioning revenue received from ComEd in 2003 compared to 2002.

Purchased Power and Fuel

Generation’s supply of sales in 2003 and 2002, excluding the trading portfolio, was as follows:


Supply of Sales (in GWhs)	2003	2002	% Change
Nuclear generation (1)	117,502	115,854	1.4	%
Purchases - non-trading portfolio (2)	82,860	78,710	5.3	%
Fossil and hydroelectric generation	24,310	12,976	87.3	%

Total supply	224,672	207,540	8.3	%

(1)	Excluding AmerGen.

(2)	Including purchased power agreements with AmerGen.


($/MWh)	2003		2002		% Change
Average supply cost (1) – excluding trading portfolio	$	22.79	$	20.49	11.2	%

(1)	Average supply cost includes purchased power and fuel costs.

Generation’s supply mix changed as a result of:

•

Increased nuclear generation due to a lower number of refueling outages during 2003 as compared to 2002,

•

Increased fossil generation due to the Exelon New England plants acquired in November 2002, which became operational in the second and third quarters of 2003 and account for an increase of 8,426 GWhs, and

•

Additional purchase power of 3,320 GWhs due to the acquisition of Exelon New England, a new PPA with AmerGen which increased 3,049 GWhs in the second quarter of 2003, as well as 11,989 GWhs of other miscellaneous power purchases which more than offset a 14,208 GWh decrease in purchased power from Midwest Generation.

The increase in purchased power expense was primarily attributable to a 5.3% increase in purchased power volume and an increase of $3.50/MWh in the average market price of purchased power between 2003 and 2002.

Fuel expense increased in 2003 as compared to 2002, as summarized below:


(in millions)	2003		2002		Variance		% Change
Nuclear generation (1)	$	502	$	483	$	19	3.9	%
Fossil and hydroelectric generation		1,031		476		555	116.6	%

Total supply	$	1,533	$	959	$	574	59.9	%

(1)	Excluding AmerGen.

The increase was principally attributable to increased fossil fuel purchases related to generating asset acquisitions in Texas and New England in 2002, as well as increased peaking production due to summer demand and higher average prices.

Operating and Maintenance

The increase in operating and maintenance (O&M) expense in 2003 as compared to 2002 was primarily attributable to $60 million of severance and related postretirement health and welfare benefits accruals and pension and postretirement curtailment costs associated with The Exelon Way and $197 million of accretion expense related to the new decommissioning accounting policy as a result of implementing SFAS No. 143.

Accretion expense includes $153 million of accretion of the asset retirement obligation and $44 million to adjust the earnings impact of certain of the nuclear decommissioning revenues earned from ComEd and PECO, nuclear decommissioning trust fund investment income related to certain nuclear facilities, income taxes incurred on certain nuclear decommissioning trust fund activities, accretion of the asset retirement obligation and depreciation of the asset retirement cost asset to zero. The increase in O&M was also due to $54 million of additional employee payroll and benefits costs and $78 million of additional expenses due to generating asset acquisitions made in 2002. Also, Generation recorded an impairment charge of $7 million in 2003, of which $5 million is related to the pending retirement of Mystic Station Units 4, 5 and 6. These increases were partially offset by $49 million of lower nuclear refueling outage costs, including $19 million for Generation’s ownership interest in Salem, which is operated by the co-owner, PSE&G, executive severance expense recorded in 2002 of $19 million, an $8 million reduction in worker’s compensation expense and $31 million related to other non-recurring items.


	2003			2002
Nuclear fleet capacity factor (1)		93.4	%		92.7	%
Nuclear fleet production cost per MWh (1)	$	12.53		$	13.00
Average purchased power cost for wholesale operations per MWh	$	43.29		$	41.85

(1)	Including AmerGen and excluding Salem.

The higher nuclear capacity factor and decreased production costs are primarily due to 56 fewer planned refueling outage days, resulting in a $36 million decrease in outage costs, including a $6 million decrease related to AmerGen, in 2003 as compared to 2002. The years ended 2003 and 2002 included 30 and 26 unplanned outages, respectively, resulting in a $2 million increase in non-refueling outage costs in 2003 as compared to 2002.

Depreciation and Amortization

The decrease in depreciation and amortization expense in 2003 as compared to 2002 was primarily attributable to a $130 million reduction in decommissioning expense net of ARC depreciation, as these costs are included in operating and maintenance expense after the adoption of SFAS No. 143 and a $12 million decrease due to life extensions of assets acquired in 2002. The decrease was partially offset by $65 million of additional depreciation expense on capital additions placed in service in 2002, of which $18 million of expense is related to plant acquisitions made after the third quarter of 2002.

Taxes Other Than Income

Taxes other than income decreased in 2003 compared to 2002 due primarily to a $20 million decrease in property taxes, a $13 million decrease in the Pennsylvania capital stock tax and Texas franchise tax, and a $6 million decrease in payroll taxes.

Interest Expense

The increase in interest expense in 2003 as compared to 2002 is due to $18 million of higher interest related to the Boston Generating project debt outstanding in 2003 as well as the outstanding Sithe note. The increase was partially offset by a $14 million decrease resulting from interest expense no longer being recorded to offset decommissioning interest income in 2003. This offset is currently included as accretion expense in operating and maintenance expense.

Equity in Earnings of Unconsolidated Affiliates

The decrease in equity in earnings of unconsolidated affiliates in 2003 as compared to 2002 was due to a decrease of $21 million in the equity in earnings of Sithe, which was primarily the result of the sale of Sithe New England’s assets to Generation in November 2002. A decrease of $17 million in the equity in earnings of AmerGen also contributed to the overall decrease, which was primarily due to lower PPA revenues at AmerGen and increases in severance costs during 2003.

Other, Net

The decrease in other, net in 2003 as compared to 2002 was primarily a result of $255 million of impairment charges related to Generation’s equity investment in Sithe due to an other-than-temporary decline in value and a $25 million loss resulting from the subsequent sale of 50% of the assets of Sithe to Reservoir (see Note 3 to Generation’s Notes to Consolidated Financial Statements). These decreases were partially offset by $16 million increase in decommissioning trust fund investment income.

Income Taxes

The effective income tax rate was 42.6% for 2003 compared to 35.9% for 2002. This increase was primarily attributable to the impairments recorded in 2003 related to the long-lived assets of Boston Generating and Generation’s investment in Sithe, which resulted in a pre-tax loss. Other adjustments that affected income taxes include a decrease in tax-exempt interest recorded in 2003 and an increase in nuclear decommissioning investment income for 2003.

Cumulative Effect of Changes in Accounting Principles

On January 1, 2003, Generation adopted SFAS No. 143 resulting in a benefit of $108 million (net of income taxes of $70 million).

On January 1, 2002, Generation adopted SFAS No. 142 resulting in a benefit of $13 million (net of income taxes of $9 million).

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

Significant Operating Trends – Generation


	2002			2001			Variance			% Change
OPERATING REVENUES	$	6,858		$	6,826		$	32		0.5	%

OPERATING EXPENSES
Purchased power		3,294			3,106			188		6.1	%
Fuel		959			889			70		7.9	%
Operating and maintenance		1,656			1,528			128		8.4	%
Depreciation		276			282			(6	)	(2.1	)%
Taxes other than income		164			149			15		10.1	%

Total operating expense		6,349			5,954			395		6.6	%

OPERATING INCOME		509			872			(363	)	(41.6	)%

OTHER INCOME AND DEDUCTIONS
Interest expense		(75	)		(115	)		40		(34.8	)%
Equity in earnings of unconsolidated affiliates		87			90			(3	)	(3.3	)%
Other, net		83			(8	)		91		n.m.

Total other income and deductions		95			(33	)		128		n.m.

INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES		604			839			(235	)	(28.0	)%

INCOME TAXES		217			327			(110	)	(33.6	)%

INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES		387			512			(125	)	(24.4	)%

CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES, (net of income taxes)		13			12			1		8.3	%

NET INCOME	$	400		$	524		$	(124	)	(23.7	)%

n.m. not meaningful

100

Net Income

Net income in 2002 was adversely affected 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.

Operating Revenues

Operating revenues increased in 2002 as compared to 2001. For 2002 and 2001, Generation’s sales were as follows:


Revenue (in millions)	2002			2001		Variance			% Change
Energy Delivery and Exelon Energy Company	$	4,213		$	4,089	$	124		3.0	%
Market sales		2,591			2,676		(85	)	(3.2	)%

Total energy sales revenue		6,804			6,765		39		0.6	%

Trading portfolio		(29	)		7		(36	)	n.m.
Other revenue		83			54		29		53.7	%

Total revenue	$	6,858		$	6,826	$	32		0.5	%

n.m.	– not meaningful


Sales (in GWhs)	2002	2001	% Change
Energy Delivery and Exelon Energy Company	123,975	123,793	0.1	%
Market sales	83,565	72,333	15.5	%

Total sales	207,540	196,126	5.8	%

Trading volume of 69,933 GWhs and 5,754 GWhs for the years 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 and Exelon Energy Company	$	33.98	$	33.05	2.8	%
Market sales		31.01		37.00	(16.2	)%
Total - excluding the trading portfolio		32.78		34.51	(5.0	)%

Exelon Delivery and Exelon Energy Company. Sales to affiliates increased by $124 million. The increase was primarily attributable to higher prices under PPAs. Also, Generation had higher volume sales to ComEd, offset by slightly lower volume sales to PECO and Exelon Energy Company.

Market Sales. Revenue from market sales decreased primarily due to a $6/MWh decrease in average market prices in 2002 compared to 2001. The decrease was partially offset by an increase in market sales volume.

Trading Revenues. Trading revenue decreased, reflecting a $29 million loss for the year ended December 31, 2002 as compared to a $7 million gain in the same period in 2001. The decrease was primarily related to an increase in gas prices in April 2002, which negatively affected Generation’s trading positions.

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Other Revenue.Other revenue increased $29 million in 2002 as compared to 2001, primarily as a result of increased gas sales resulting from the Texas generating asset acquisitions in April 2002.

Purchased Power and Fuel

Generation’s supply of sales in 2002 and 2001, excluding the trading portfolio, were as follows:


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 hydroelectric generation	12,976	11,345	14.4	%

Total supply	207,540	196,126	5.8	%

(1)	Excluding AmerGen.

(2)	Including PPAs with AmerGen.

The increase in purchased power expense was primarily attributable to increased power supplied to Generation which resulted in a 15.8% increase in purchased power volume. This was partially offset by average purchased power cost decreasing by $4.11/MWh for 2002 as compared to 2001. This decrease in average purchased power cost was principally attributable to lower realized wholesale market prices and reduced transmission costs.

The increase in fuel expense in 2002 was primarily attributable to increased fossil fuel purchases related to generating asset acquisitions in Texas and New England, as well as increased peaking production due to summer demand.

Operating and Maintenance

The increase in O&M expense in 2002 as compared to 2001 was due to the additional 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 an Exelon cost management initiative. The severance reduction represents a reversal of costs previously charged to operating expense.


	2002			2001
Nuclear fleet capacity factor (1)		92.7	%		94.4	%
Nuclear fleet production cost per MWh (1)	$	13.00		$	12.78
Average purchased power cost for wholesale operations per MWh	$	41.85		$	45.94

(1)	Including AmerGen and excluding Salem.

Depreciation and Amortization

The decrease in depreciation and amortization expense in 2002 as compared to 2001 was due to a $42 million reduction in depreciation expense arising from the extension of the useful lives on certain generating 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.

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Taxes Other Than Income

Taxes other than income increased in 2002 as compared to 2001 due primarily to an $8 million increase in property taxes.

Interest Expense

The decrease in interest expense in 2002 as compared to 2001 was due to a $19 million reduction in interest charges on the spent nuclear fuel obligation because of lower rates, and $33 million of lower affiliate interest expense. The decrease was partially offset by a $21 million increase in interest expense due to newly acquired long-term debt associated with Exelon New England.

Equity in Earnings of Unconsolidated Affiliates, net

The decrease in equity in earnings of unconsolidated affiliates in 2002 as compared to 2001 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

The increase in other, net in 2002 as compared to 2001 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 an increase in tax-exempt interest recorded in 2002 and other tax benefits recorded in 2002.

Cumulative Effect of Changes in Accounting Principles

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).

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 financing, including the issuance of commercial paper, participation in the intercompany money pool and/or capital contributions from Exelon. Generation’s working capital deficit is expected to be cured with its anticipated continuance of positive operating cash flows and the eventual elimination of its Boston Generating debt balance upon the transfer of its ownership of Boston Generating. We anticipate that the transfer of Boston Generating will be accomplished on a non-cash basis. 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. If these conditions deteriorate to where Generation no longer has access to external financing sources at reasonable terms, Generation has access to a revolving credit facility. See the Credit Issues section of Liquidity and Capital Resources for further discussion. Capital resources are used primarily to fund Generation’s capital requirements, including construction, investments in new and existing ventures, repayments of maturing debt, the payment of distributions to Exelon and contributions to Exelon’s pension plans. Any future acquisitions could require external financing or borrowings or capital contributions from Exelon.

As part of the implementation of The Exelon Way, Generation identified approximately 470 positions for elimination by the end of 2004 and recorded a charge for salary continuance severance of $33 million before income taxes during 2003, which Generation anticipates that the majority will be paid in 2004 and 2005. Generation is considering whether there are additional positions to be eliminated in 2005 and 2006. Generation may incur further severance-related costs associated with The Exelon Way if additional positions are identified to be eliminated. These costs will be recorded in the period in which the costs can be reasonably estimated.

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Cash Flows from Operating Activities

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. Cash flows from operations have been and are expected to continue to provide a reliable, steady source of cash flow, sufficient to meet operating and capital expenditures requirements for the foreseeable future. See Business Outlook and Challenges in Managing our Business.

Cash flows provided by operations for the years ended December 31, 2003 and 2002 were $1,453 million and $1,150 million, respectively. Changes in Generation’s cash flows from operations are generally consistent with changes in its results of operations, as further adjusted by changes in working capital in the normal course of business and non-cash charges.

In addition to the items mentioned in Results of Operation, Generation’s operating cash flows in 2003 were affected by the following items:

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Sales to ComEd decreased in 2003 in line with the lower load requirements of the territory due to the customer choice initiative.

•

Greater mark-to-market activity in 2002 resulted in higher cash inflows from proprietary trading activities in 2002 compared to 2003.

•

Discretionary contributions to Exelon’s defined benefit pension plans of $145 million in 2003 compared to $60 million in 2002.

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 expects to make a discretionary pension plan contribution up to approximately $419 million in 2004, of which $170 million is expected to be funded by Generation. Of the $170 million expected to be contributed to the pension plan during 2004, $17 million is estimated to be needed to satisfy IRS minimum funding requirements for the pension plan obligations assumed in the AmerGen acquisition in December 2003.

Cash Flows from Investing Activities

Cash flows used in investing activities were $1,301 million in 2003, compared to $1,686 million in 2002. Capital expenditures, including investment in nuclear fuel, were $953 million in 2003, and primarily represent additions to nuclear fuel as well as the construction of three Boston Generating facilities with projected capacity of 2,288 MWs of energy and additions and upgrades to the existing facilities. Capital expenditures were offset by $92 million of liquidating damages received from Raytheon as a result of Raytheon not meeting the expected completion date and certain contractual performance criteria in connection with Raytheon’s construction of the Boston Generating facilities.

On November 25, 2003, Generation, Reservoir, and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe. See Contractual Obligations and Off-Balance Sheet Arrangements – Variable Interest Entities below for further information regarding this transaction. In addition, a note receivable was received from EXRES SHC, Inc. for $92 million. In December 2003, Generation purchased the 50% interest in AmerGen held by British Energy plc for $240 million, net of cash acquired of $36 million. The acquisition was funded with cash provided by operations.

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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%. As of December 31, 2002, the balance of the loan to AmerGen was $35 million, which was repaid in its entirety during 2003. In April 2002, Generation purchased two natural-gas and oil-fired generating plants from TXU for $443 million. The purchase was funded with commercial paper, which Exelon issued and Generation repaid with cash flows from operations. In November 2002, Generation purchased Exelon New England, which resulted in a use of cash of $2 million, net of $12 million of cash acquired. The remainder of the purchase price was financed with a $534 million note payable to Sithe, which was subsequently increased to $536 million. At December 31, 2003, Generation had repaid $446 million of the note payable to Sithe, leaving a balance of $90 million, which is payable on the earlier of December 1, 2004, upon reaching certain Sithe liquidity requirements, or upon a change of control.

Capital expenditures for 2004 are projected to be $972 million. Generation anticipates that nuclear refueling outages will increase from eight in 2003 to ten in 2004. Generation’s capital expenditures are expected to be funded by internally generated funds.

Cash Flows from Financing Activities

Cash flows used in financing activities were $52 million in 2003, compared to $370 million cash provided in 2002. The decrease in cash flows used in financing activities was primarily a result of the retirement of debt of $570 million and the repayment of the acquisition note payable to Sithe of $446 million. Additional decreases resulted from the payment of distributions totaling $189 million and lower borrowings from affiliates resulting in $242 million of the change from the prior year. This decrease was partially offset by the issuance of $500 million of unsecured notes in December 2003 and the bridge financing facility of $550 million.

Financing activities in 2003 exclude the $17 million non-cash distribution to PECO and in 2002 exclude the non-cash issuance of a $534 million note (subsequently increased to $536 million) issued to Sithe for the 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, 2003 and 2002.

Credit Issues

Exelon Credit Facility.Generation meets its short-term liquidity requirements primarily through the issuance of commercial paper and intercompany borrowings from Exelon’s intercompany money pool. In October 2003, Exelon, ComEd, PECO and Generation replaced their $1.5 billion bank unsecured revolving credit facility with a $750 million 364-day unsecured revolving credit agreement and a $750 million 3-year unsecured revolving credit agreement with a group of banks. Both revolving credit agreements are used principally to support the commercial paper programs at Exelon, ComEd, PECO and Generation and to issue letters of credit. The 364-day agreement also includes a term-out option provision that allows a borrower to extend the maturity of revolving credit borrowings outstanding at the end of the 364-day period for one year.

At December 31, 2003, Generation’s aggregate sublimit under the credit agreements was $250 million. Sublimits under the credit agreements can change upon written notification to the bank group. Generation had approximately $170 million of unused bank commitments under the credit agreements at December 31, 2003. Generation did not have any commercial paper outstanding at December 31, 2003. Interest rates on the advances under the credit facility are based on either the London Interbank Offering Rate (LIBOR) or prime plus an adder based on the credit rating of the borrower as well as the total outstanding amounts under the agreement at the time of borrowing. The maximum adder would be 175 basis points.

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 Exelon New England’s debt. Generation’s threshold for the ratio reflected in the credit agreements cannot be less than 3.25 to 1 for the twelve-month period ended December 31, 2003. At December 31, 2003, Generation was in compliance with the credit agreement thresholds.

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Capital Structure.At December 31, 2003, Generation’s capital structure consisted of 48% member’s equity, 8% notes payable and 44% long-term debt. Long-term debt includes $1.2 billion of senior unsecured notes and $1.0 billion Boston Generating project debt, representing 36% of capitalization.

Boston Generating Project Debt.Boston Generating has a $1.25 billion credit facility (Boston Generating Facility), which was entered into primarily to finance the development and construction of generating projects known as Mystic 8 and 9 and Fore River. Approximately $1.0 billion of debt was outstanding under the Boston Generating Facility at December 31, 2003, all of which was reflected in Generation’s Consolidated Balance Sheets as a current liability due to certain events of default described below. The Boston Generating Facility is non-recourse to Generation and an event of default under the Boston Generating Facility does not constitute an event of default under any other of Generation’s debt instruments or the debt instruments of its subsidiaries.

The Boston Generating Facility required that all of the projects achieve “Project Completion,” as defined in the Boston Generating Facility (Project Completion) by July 12, 2003. Project Completion was not achieved by July 12, 2003, resulting in an event of default under the Boston Generating Facility. Mystic 8 and 9 and Fore River have begun commercial operation, although they have not yet achieved Project Completion.

Generation has commenced the process of an orderly transition out of the ownership of Boston Generating and the Mystic 8 and 9 and Fore River generating projects. Generation’s decision to transition out of the projects was made as a result of its evaluation of the projects and discussions with the lenders under the Boston Generating Facility. We anticipate that this transition will occur in 2004.

Generation Revolving Credit Facilities.On September 29, 2003, Generation closed on an $850 million revolving credit facility that replaced a $550 million revolving credit facility that had originally closed on June 13, 2003. Generation used the facility to make the first payment to Sithe relating to the $536 million note that was used to purchase Exelon New England. This note was restructured in June 2003 to provide for a payment of $210 million of the principal on June 16, 2003, payment of $236 million of the principal on the earlier of December 1, 2003 or upon a change of control of Generation, and payment of the remaining principal on the earlier of December 1, 2004, upon reaching certain Sithe liquidity requirements, or upon a change of control of Generation. Generation paid $446 million on the note to Sithe in 2003. Generation terminated the $850 million revolving credit facility on December 22, 2003.

Intercompany Money Pool. To provide an additional short-term borrowing option that could 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 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 Corporate may participate as a lender. Funding of, and borrowings from, the money pool are predicated on whether the contributions and borrowings result in economic benefits. Interest on borrowings is based on short-term market rates of interest, or, if from an external source, specific borrowing rates. During 2003, Generation had various borrowings from the money pool. The maximum amount of borrowings outstanding at any time during 2003 by Generation was $395 million. As of December 31, 2003, Generation owed the money pool $301 million on these loans. For the year ended December 31, 2003, Generation paid $2 million in interest to the money pool.

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Security Ratings.Generation’s access to the capital markets, including the commercial paper market, and its financing costs in those markets are dependent on its securities ratings. In the fourth quarter of 2003, Standard & Poor’s Ratings Services affirmed Generation’s corporate credit ratings but revised its outlook to negative from stable. 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 fees and interest charges under certain bank credit facilities. The following table shows Generation’s securities ratings at December 31, 2003:


Securities	Moody’s Investors Service	Standard & Poor’s	Fitch Ratings
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.

As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of capacity, energy, fuels and emissions allowances. These contracts either contain express provisions or otherwise permit Generation’s counterparties and Generation to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed to provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of Generation’s situation at the time of the demand. If Generation can reasonably claim that it is willing and financially able to perform its obligations, it may be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient.

Fund Transfer Restrictions.Under applicable law, 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, 2003, Generation had undistributed earnings of $602 million.

Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations

Generation’s contractual obligations as of December 31, 2003 are as follows:


			Payment Due within						Due After 5 Years
(in millions)	Total		1 Year		2-3 Years		4-5 Years		Due After 5 Years
Long-term debt	$	2,728	$	1,068	$	23	$	20	$	1,617
Short-term note to Sithe		90		90		—		—		—
Intercompany money pool		301		301		—		—		—
Short-term obligation to Exelon		115		115		—		—		—
Operating leases		564		21		53		52		438
Power purchase obligations		10,475		2,635		1,827		1,410		4,603
Fuel purchase agreements		3,034		476		825		582		1,151
Other purchase commitments		54		19		22		13		—
Obligation to minority shareholders		54		3		6		6		39
Pension IRS minimum funding requirement		17		17		—		—		—
Spent nuclear fuel obligations		867		—		—		—		867

Total contractual obligations	$	18,299	$	4,745	$	2,756	$	2,083	$	8,715

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

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long-term debt, see Note 8

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short-term note to Sithe, see Note 15

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intercompany money pool, see Note 15

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short-term obligation to Exelon, see Note 15

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operating leases, see Note 13

•

power purchase obligations, see Note 13

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obligation to minority shareholders, see Note 13

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pension IRS minimum funding requirement, see Note 11

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spent nuclear fuel obligation, see Note 10

Two affiliates of Exelon New England have long-term supply agreements through December 2022 with Distrigas for gas supply, primarily for the Boston Generating units. Under the agreements, prices are indexed to New England gas markets. Exelon New England has guaranteed these entities’ financial obligations to Distrigas under the Distrigas agreements. It is currently anticipated that Exelon New England’s guaranty to Distrigas will continue following the eventual transfer of the ownership interests in Boston Generating. This guaranty is non-recourse to Generation. At December 31, 2003, Exelon New England had net assets of approximately $70 million, exclusive of the Boston Generating net assets.

Generation has an obligation to decommission its nuclear power plants. Upon adoption of SFAS No. 143, “Asset Retirement Obligations” (SFAS No. 143), Generation was required to re-measure its decommissioning liabilities at fair value and recorded an asset retirement obligation of $2.4 billion on January 1, 2003. Increases in the asset retirement obligation are recorded as operating and maintenance expense. At December 31, 2003, the asset retirement obligation recorded within Generation’s Consolidated Balance Sheet was $3.0 billion. 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. To fund future decommissioning costs, Generation held $4.7 billion of investments in trust funds, including net unrealized gains and losses, at December 31, 2003. See ITEM 8. Financial Statements and Supplementary Data – Generation, Notes to Consolidated Financial Statements for further discussion of Generation’s decommissioning obligation.

See Note 13 of the Notes to Consolidated Financial Statements for discussion of Generation’s commercial commitments as of December 31, 2003.

Variable Interest Entities.Generation is a 50% owner of Sithe and accounts for the investment as an unconsolidated equity investment. Based on management’s interpretation of FIN No. 46-R, it is reasonably possible that Generation will consolidate Sithe as of March 31, 2004. At December 31, 2003, Sithe had total assets of $1.5 billion (including the $90 million note from Generation) and total debt of $1.0 billion. The $1.0 billion of debt includes $588 million of subsidiary debt incurred primarily to finance the construction of six new generating facilities, $419 million of subordinated debt, $43 million of current portion of long-term debt, but excludes $469 million of non-recourse debt associated with Sithe’s equity investments. For the year ended December 31, 2003, Sithe had revenues of $690 million and incurred a net loss of approximately $72 million. Generation contractually does not own any interest in Sithe International, a subsidiary of Sithe. As such, a portion of Sithe’s net assets and results of operations would be eliminated from Generation’s Consolidated Balance Sheets and Consolidated Statements of Income through a minority interest if Sithe is consolidated under FIN No. 46-R as of March 31, 2004. As of December 31, 2003, Generation had a $47 million investment in Sithe.

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In 2003, Generation recorded impairment charges of $255 million (before income taxes) in other income and deductions within the Consolidated Statements of Income associated with a decline in the fair value of the Sithe investment, which was considered to be other-than-temporary. Generation considered various factors in the decision to impair this investment, including its negotiations to sell its interest in Sithe and the completion of the transactions described below. The discussions surrounding the sale and the resulting transactions indicated that the fair value of the Sithe investment was below its book value and, as such, an impairment was required.

Following the sales of the above entities, Generation transferred its wholly owned subsidiary that held the Sithe investment to a newly formed holding company. The subsidiary holding the Sithe investment acquired the remaining Sithe interests from Apollo and Marubeni for $612 million using proceeds from a $580 million bridge financing and available cash. Generation sold a 50% interest in the newly formed holding company for $76 million to an entity controlled by Reservoir on November 25, 2003. On November 26, 2003, Sithe distributed $580 million of available cash to its parent, which then utilized the distributed funds to repay the bridge financing.

In connection with this transaction, Generation recorded obligations related to $39 million of guarantees in accordance with FASB Interpretation (FIN) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others” (FIN No. 45). These guarantees were issued to protect Reservoir from credit exposure of certain counter-parties through 2015 and other indemnities. In determining the value of the FIN No. 45 guarantees, Generation utilized a probabilistic model to assess the possibilities of future payments under the guarantees.

Both Generation and Reservoir’s 50% interests in Sithe are subject to put and call options that could result in either party owning 100% of Sithe. While Generation’s intent is to fully divest Sithe, the timing of the put and call options vary by acquirer and can extend through March 2006. The pricing of the put and call options is dependent on numerous factors, such as the acquirer, date of acquisition and assets owned by Sithe at the time of exercise. Any closing under either the put or call options is conditioned upon obtaining state and federal regulatory approvals.

Other

Generation’s cash-flow hedges are affected 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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Critical Accounting Policies and Estimates

See ComEd, PECO and Generation – Critical Accounting Policies and Estimates above for a discussion of Generation’s critical accounting policies and estimates.

Business Outlook and the Challenges in Managing Our Business

The U.S. electric generation, transmission and distribution industry is in the midst of a fundamental and, at this point, uncertain transition from a fully regulated industry offering bundled service to an industry with unbundled services, some of which are regulated and others of which are priced in competitive markets. Generation operates in a highly competitive environment which is capital intensive.

The challenges affecting Generation’s business are discussed below. Further discussion of Generation’s liquidity position and capital resources and related challenges is included in the Liquidity and Capital Resources section.

Generation must effectively manage its power portfolio to meet its contractual commitments and to handle changes in the wholesale power markets.

The majority of Generation’s portfolio is used to provide power under long-term PPAs to ComEd and PECO. To the extent the portfolio is not needed for that purpose, Generation’s output is sold in the wholesale market. Generation’s ability to grow is dependent upon its ability to cost-effectively meet the load requirements of ComEd and PECO, to manage its power portfolio and to effectively handle changes in the wholesale power markets.

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

Generation’s resources include interests in 11 nuclear generation stations, consisting of 19 units. Generation’s nuclear fleet, excluding AmerGen’s three units, generated 117,502 GWhs, or more than half of its total supply, in 2003. 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. Generation’s nuclear plants benefit from stable fuel costs, minimal environmental impact from operations and a safe operating history.

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 risks, including:

•

mechanical or structural problems;

•

inadequacy or lapses in maintenance protocols;

•

impairment of reactor operation and safety systems due to human error;

•

costs of storage, handling and disposal of nuclear materials;

•

limitations on the amounts and types of insurance coverage commercially available; and

•

uncertainties regarding both technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives.

The material risks known or currently anticipated that could affect Generation’s ability to sustain its current levels of profitability are:

Nuclear capacity factors. Capacity factors, particularly nuclear capacity factors, significantly affect results of operations. Nuclear plant operations involve substantial fixed operating costs but produce electricity at low

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variable costs due to low fuel costs. Consequently, to be successful, Generation must consistently operate its nuclear generating facilities at high capacity factors. Lower capacity factors would increase Generation’s 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 Generation’s obligations to ComEd and PECO and other committed third-party sales. These sources generally are at a higher cost than Generation otherwise would have incurred to generate energy from its own nuclear stations.

Refueling outages. 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 26 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-six day outage, depending on the capacity of the station, will decrease the total nuclear annual capacity factor between 0.3% and 0.5%. The number of refueling outages, including AmerGen, will increase to ten in 2004 from nine in 2003. Maintenance expenditures are expected to increase by approximately $20 million in 2004 as compared to 2003 as a result of the increased number of nuclear refueling outages.

Nuclear fuel quality. The quality of nuclear fuel utilized by Generation can affect the efficiency and costs of its operations. Certain of Generation’s nuclear units have been identified as having a limited number of fuel performance issues. Remediation actions, including those required to address performance issues, have resulted in increased costs due to accelerated fuel amortization and/or increased outage costs and could continue to do so. It is difficult to predict the total cost of these remediation procedures.

Life extensions. Generation’s nuclear facilities are currently operating under 40-year NRC licenses. Generation has applied for 20-year extensions for the licenses that will be expiring in the next ten years, excluding licenses for the AmerGen facilities. Generation anticipates filing a request for a license extension for Oyster Creek and is evaluating the other AmerGen facilities for possible extension. Generation has received a 20-year extension of the license for the Peach Bottom units, but Generation cannot predict whether any of the other pending extensions will be granted. Generation intends to evaluate opportunities, as permitted by the NRC, to apply for life extensions to some or all of the remaining licenses. If the extensions are granted, Generation cannot be sure that it will be willing to operate the facilities for all or any portion of the extended license. If the NRC does not extend the operating licenses for Generation’s nuclear stations, its results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning payments.

Regulatory risk. The NRC may modify, suspend or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations or the terms of the licenses for nuclear facilities. A change in the Atomic Energy Act or the applicable regulations or licenses may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and significantly affect Generation’s results of operation or financial position. Events at nuclear plants owned by others, as well as those owned by Generation, may cause the NRC to initiate such actions.

Operational risk. Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation has to shut down the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. Generation may choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation may lose revenue and incur increased fuel and purchased power expense to meet supply commitments. For plants operated but not wholly owned by Generation, Generation may also incur liability to the co-owners.

Nuclear accident risk. Although the safety record of nuclear reactors generally, including Generation’s, 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 include loss of life and property damage. Any resulting

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liability from a nuclear accident may exceed Generation’s resources, including insurance coverages, and significantly affect Generation’s results of operation or financial position.

Nuclear liability insurance.The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. The limit as of January 1, 2004 is $10.9 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance (currently $300 million for each operating site). Claims exceeding that amount are covered through mandatory participation in a financial protection pool. The Price-Anderson Act expired on August 1, 2002 and was subsequently extended to the end of 2003 by the U.S. Congress. Only facilities applying for NRC licenses subsequent to expiration of the Price-Anderson Act are affected. Existing commercial generating facilities, such as those owned and operated by Generation, remain subject to the provisions of the Price-Anderson Act and are unaffected by its expiration.

Decommissioning. Generation has an obligation to decommission its nuclear power plants. Based on estimates of decommissioning costs for each of the nuclear facilities in which Generation has an ownership interest, other than the AmerGen facilities, the ICC permits ComEd, and the PUC permits PECO, to collect from their 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. The ICC permitted ComEd to recover $73 million per year from retail customers for decommissioning for the years 2001 through 2004, and, depending upon the portion of the output of certain generating stations taken by ComEd, up to $73 million annually in 2005 and 2006. Subsequent to 2006, there will be no further recoveries of decommissioning costs from ComEd’s customers. Effective January 1, 2004, PECO will be permitted to recover $33 million annually for nuclear decommissioning. Generation expects that these collections will continue through the operating license life of each of the former PECO units, with adjustments every five years to reflect changes in cost estimates and decommissioning trust fund performance. 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. To fund future decommissioning costs, Generation held $4.7 billion of investments in trust funds, including net unrealized gains and losses, at December 31, 2003.

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. Generation is required to provide to the NRC a biennial report by unit (annually for Generation’s four retired units) addressing Generation’s ability to meet the NRC-estimated funding levels (NRC Funding Levels) with scheduled contributions to and earnings on the decommissioning trust funds. As of December 31, 2003, Generation had a number of units, which, at current market levels, are being funded at a rate less than anticipated with respect to the NRC’s Funding Levels. Generation will submit its next biennial report to the NRC at the end of March 2005. 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.

In 2003, the General Accounting Office (GAO) published a study on the NRC’s need for more effective analyses to ensure the adequate accumulation of funds to decommission nuclear power plants in the United States. As it has in the past, the GAO concluded that accumulated and future proposed funding was inadequate to achieve NRC Funding Levels at a number of U.S. nuclear plants, including a number of Generation’s plants. Generation has reviewed the GAO’s report and believe that, in reaching its conclusions, the GAO did not consider all aspects of Generation’s decommissioning strategy, such as fund growth during the decommissioning period. The inclusion of estimated earnings growth on Generation’s nuclear trust funds during the decommissioning period virtually eliminates any funding shortfalls identified in the GAO report.

In spite of any temporary shortfall in NRC Funding Levels, Generation currently believes that the amounts in nuclear decommissioning trust funds and future collections from ratepayers, together with earnings thereon, will provide adequate funding to decommission its nuclear facilities in accordance with regulatory requirements. Forecasting investment earnings and costs to decommission nuclear generating stations requires significant

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judgment, and actual results may differ significantly from current estimates. Ultimately, when decommissioning activities are initiated, if the investments held by Generation’s nuclear decommissioning trusts are not sufficient to fund the decommissioning of Generation’s nuclear plants, Generation may be required to identify other means of funding its decommissioning obligations.

Generation relies on electric transmission facilities that it does not own or control. If operations at these facilities are disrupted or do not provide Generation with adequate transmission capacity, it may not be able to deliver its wholesale electric power to the purchasers of the power.

Generation depends on transmission facilities owned and operated by other companies to deliver the power that it sells at wholesale. If transmission at these facilities is disrupted, or transmission capacity is inadequate, Generation may not be able to sell and deliver its wholesale power. While Generation was not significantly affected by the failure in the transmission grid that served a large portion of the Northeastern United States and Canada on August 14, 2003, the North American transmission grid is highly interconnected and, in extraordinary circumstances, disruptions at a point within the grid can cause a systemic response that results in an extensive power outage. If a region’s power transmission infrastructure is inadequate, Generation’s recovery of wholesale costs and profits may be limited. In addition, if restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.

The FERC has issued electric transmission initiatives that require electric transmission services to be offered unbundled from commodity sales. Although these initiatives are designed to encourage wholesale market transactions for electricity, access to transmission systems may in fact not be available if transmission capacity is insufficient because of physical constraints or because it is contractually unavailable. Generation also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.

Generation is directly affected by price fluctuations and other risks of the wholesale power market.

Generation fulfills its energy commitments from the output of the generating facilities that it owns as well as through buying electricity in both the wholesale bilateral and spot markets. The excess or deficiency of energy owned or controlled by Generation compared to its obligations exposes Generation to the risks of rising and falling prices in those markets, and Generation’s cash flows may vary accordingly. To the extent Generation does not supply power to serve the needs of ComEd and PECO, Generation’s cash flows will largely be determined by wholesale prices of electricity and its ability to successfully market energy, capacity and ancillary services. In the event that lower wholesale prices of electricity reduce Generation’s current or forecasted cash flows, the carrying value of Generation’s generating units may be determined to be impaired.

The wholesale spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. 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 natural gas plus the cost to convert natural gas to electricity. Therefore, changes in the supply and cost of natural gas generally affect the open market wholesale price of electricity.

Credit Risk. In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money or energy as a result of market transactions will not perform their obligations. For example, energy supplied by third-party generators, including Sithe, under long-term agreements represents a significant portion of Generation’s overall capacity. These generators face operational risks, such as those that Generation faces, and their ability to perform 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. In the spot markets, Generation is exposed to the risks of whatever default mechanisms exist in that market, some of

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which attempt to spread the risk across all participants, which may or may not be an effective way of lessening the severity of the risk and the amounts at stake. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties.

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. These policies include counterparty credit limits and, in some cases, require deposits or 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.

Immature Markets.The wholesale spot markets are new and evolving markets that vary from region to region and are still developing practices and procedures. While the FERC has proposed initiatives to standardize wholesale spot markets, Generation cannot predict whether that effort will be successful, what form any of these markets will eventually take or what roles Generation will play in them. Problems in or the failure of any of these markets, as was experienced in California in 2000, could adversely affect Generation’s business.

Hedging. The Power Team buys and sells energy and other products in the wholesale markets and enters into financial contracts to manage risk and hedge various positions in Generation’s power generation portfolios. This activity, along with the effects of any specialized accounting for trading contracts, may cause volatility in Generation’s future results of operations.

Weather. Generation’s operations are affected by weather, which affects demand for electricity as well as operating conditions. Generation plans 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 source or 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 incorporates contingencies into its planning for extreme weather conditions, including potentially reserving capacity to meet summer loads at levels representative of warmer-than-normal weather conditions.

Excess capacity. Energy prices are also affected 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 commencing commercial operations which has driven down power prices over the last few years. In fact, an excess supply situation currently exists in many parts of the country which has reduced prices in the wholesale markets and adversely affected Generation’s profitability. We cannot predict when these regions will return to more normal levels in the supply-demand balance.

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

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

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Wholesale markets have only been implemented in certain areas of the country and each market has unique features that may create trading barriers among the markets. The FERC has proposed initiatives, including Order 2000 and the proposed wholesale market platform rule, to encourage the development of large regional, uniform markets and to eliminate trade barriers. These initiatives, however, have not yet led to the development of such markets in all areas of the country. PJM’s market strongly resembles the 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 supports the 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 27% of Generation’s generating assets, which includes directly owned assets and capacity obtained through long-term contracts, are located in the region encompassed by PJM. If the PJM market is expanded to the Midwest, 79% of Generation’s generating assets would be located within that market. The PJM market has been the most successful and liquid regional market. Generation’s future results of operations may be affected by the successful expansion of that market to the Midwest and the implementation of any market changes mandated by the FERC.

Provider of Last Resort.As discussed above, ComEd and PECO each have POLR obligations that they have effectively transferred to Generation through full-requirements contracts. Because the choice of electricity generation supplier lies with the customer, planning to meet these obligations has a higher level of uncertainty than that traditionally experienced due to weather and the economy. It is difficult for Generation to plan the energy demand of ComEd and PECO customers. The uncertainty regarding the amount of ComEd and PECO load for which Generation must prepare increases Generation’s costs. A significant under-estimation of ComEd’s and PECO’s electric-load requirements could result in Generation not having enough power to cover its supply obligation, in which case Generation would be required to buy power from third parties or in the spot markets at prevailing market prices. Those prices may not be as favorable or as manageable as Generation’s long-term supply expenses and thus could increase total costs.

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

Generation’s business is capital intensive and requires significant investments in energy generation. The inability of Generation to effectively manage its capital projects could adversely affect its results from operations.

In 2002, Generation purchased the assets of Sithe New England Holdings, LLC (now known as Exelon New England), a subsidiary of Sithe, and related power marketing operations. Due to the reduction in power prices and delays in construction completion, in July 2003, Generation commenced the process of an orderly transition out of the ownership of the Boston Generating assets. Generation recorded an impairment charge of $945 million before income taxes related to the long-lived assets of Boston Generating as a result of its decision to exit these facilities. Charges could result from decisions to exit other investments or projects in the future. These charges could have a significant impact on Generation’s results of operations.

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. These new generating facilities may be more efficient than Generation’s

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facilities. The introduction of new technologies could increase competition, which could lower prices and have an adverse effect on Generation’s results of operations or financial condition. Generation’s financial performance depends on its ability to respond to competition in the energy industry.

Power Team’s risk management policies cannot fully eliminate the risk associated with its power trading activities.

Power Team’s power trading (including fuel procurement and power marketing) activities expose Generation to risks of commodity price movements. Generation attempts to manage its exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not always be followed or may not work as planned and cannot eliminate the risks associated with these activities. Even when Generation’s policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations may be diminished if the judgments and assumptions underlying those decisions prove to be wrong or inaccurate. Factors such as future prices and demand for power and other energy-related commodities become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, Generation cannot predict the impact that its power trading and risk management decisions may have on its business, operating results or financial position.

Capital Markets and Financing Environment

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

The ability to grow Generation’s business is affected by the ability to finance capital projects.

Generation’s business requires considerable capital resources. When necessary, Generation secures funds 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. Management currently anticipates primarily using internally generated cash flows and short-term financing through commercial paper to fund operations as well as long-term external financing sources to fund capital requirements as the needs and opportunities arise. The ability to arrange debt financing, to refinance current maturities and early retirements of debt, and the costs of issuing new debt are dependent on:

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credit availability from banks and other financial institutions,

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maintenance of acceptable credit ratings (see credit ratings in the credit issues section of Liquidity and Capital Resources above),

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investor confidence in Generation and Exelon,

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investor confidence in regional wholesale power markets,

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general economic and capital market conditions,

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the success of current projects, and

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the perceived quality of new projects.

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

Generation has investment grade ratings and has been successful in raising capital, which has been used to further its business initiatives. Also, from time to time, Generation enters into energy commodity and other

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contracts that require the maintenance of investment grade ratings. Failure to maintain investment grade ratings would cause Generation to incur higher financing costs and, in some instances, might allow certain energy commodity counterparties to close-out and terminate their contracts. Also, the failure to maintain investment grade ratings would restrict Generation’s access to the wholesale energy markets.

Market performance affects Generation’s decommissioning trust funds and Exelon’s benefit plan asset values.

The performance of the capital markets affects the values of the assets that are held in trust to satisfy Generation’s future obligations under pension and postretirement benefit plans and to decommission its nuclear generation plants. Generation has significant obligations in these areas and hold significant assets in these trusts. A decline in the market value of those assets, as was experienced from 2000 to 2002, may increase funding requirements for these obligations.

Other

Generation’s financial performance will be affected by its ability to achieve the targeted cash savings under Exelon’s new Exelon Way business model.

Generation has begun to implement Exelon’s new Exelon Way business model, which is focused on improving operating cash flows while meeting service and financial commitments through improved integration of operations and consolidation of support functions. Exelon’s targeted annual cash savings range from approximately $300 million in 2004 to approximately $600 million in 2006. Exelon has incurred expenses, including employee severance costs, associated with reaching these annual cash savings levels and is considering whether there are additional expenses to be recorded in future periods. Exelon’s targeted annual cash savings do not reflect any expenses that may be incurred in future periods. Exelon’s inability to reach these annual cash savings levels in the targeted timeframes could adversely affect its future financial performance.

Regulations imposed by the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935 affect Generation’s business operations.

Generation is subject to regulation by the Securities and Exchange Commission (SEC) under PUHCA. That regulation affects Generation’s ability to:

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diversify, by generally restricting investments to traditional electric and gas utility businesses and related businesses;

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issue securities, by requiring the prior approval of the SEC;

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engage in transactions among affiliates without the SEC’s prior approval and, then, only at cost, since the PUHCA regulates business between affiliates in a utility holding company system; and

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make dividend payments in specified situations.

Generation’s financial performance is affected by increasing costs associated with additional security measures and obtaining adequate liability insurance.

Security. Generation does not fully know the impact that future terrorist attacks or threats of terrorism may have on the industry in general and on Generation in particular. Generation has initiated security measures to safeguard its employees and critical operations from threats of terrorism and is actively participating in industry initiatives to identify methods to maintain the reliability of its energy production and delivery systems. Generation fully expects to meet or exceed all NRC-mandated measures on or before the dates specified by requirements promulgated in 2003. These requirements will necessitate additional security expenditures in 2004. Additionally, Generation is in full compliance with all pre-2003 NRC security measures. On a continuing basis,

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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.

The electric industry has also developed additional security guidelines as the result of various terrorist attacks or threats of terrorism. 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, the FERC issued minimum standards to safeguard the electric grid system control. These standards are expected to be effective in 2004 and fully implemented by January 2005. Generation participated in the development of these guidelines and is using them as a model for its security program.

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 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 terrorist acts may be limited. Generation is self-insured for deductibles and 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, together with the deductible, would negatively affect results of operations. Nuclear Electric Insurance Limited (NEIL), a mutual insurance company to which Generation belongs, provides property and business interruption insurance for Generation’s nuclear operations. In recent years, NEIL has made distributions to its members. Generation’s distribution for 2003 was $32 million, which was recorded as a reduction to operating and maintenance expenses in its Consolidated Statements of Income. Generation cannot predict the level of future distributions or if they will continue at all.

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

Generation’s business is 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 its 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 Generation and of property contaminated by hazardous substances it generates. 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, site remediation and clean-up. Also, 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, 2003, Generation’s reserve for environmental investigation and remediation costs was $10 million, exclusive of decommissioning liabilities. Generation has accrued and will continue to accrue amounts that it believes are prudent to cover these environmental liabilities, but 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.

Taxation has a significant impact on Generation’s results of operations.

Tax reserves and the recoverability of deferred tax assets.Generation is required to make judgments regarding the potential tax effects of various financial transactions and its ongoing operations to estimate its

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obligations to taxing authorities. These tax obligations include income, real estate and employment-related taxes and ongoing appeals related to these tax matters. These judgments include reserves for potential adverse outcomes regarding tax positions that Generation has taken. Generation must also assess its ability to generate capital gains in future periods to realize tax benefits associated with capital losses expected to be generated in future periods. Capital losses may be deducted only to the extent of capital gains realized during the year of the loss or during the three prior or five succeeding years. As of December 31, 2003, Generation has not recorded an allowance against its deferred tax assets associated with impairment losses which will become capital losses when realized for income tax purposes. Generation believes these deferred tax assets will be realized in future periods. The ultimate outcome of such matters could result in additional adjustments to its consolidated financial statements and such adjustments could be material.

Increases in state income taxes.Due to the revenue needs of the states in which Generation operates, various state income tax and fee increases have been proposed or are being contemplated. Generation cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by the state legislatures or regulatory bodies, and, if enacted, whether any such legislation or regulation would be effective retroactively or prospectively. If enacted, these changes could increase state income tax expense and could have a negative impact on Generation’s results of operations and cash flows.

Generation’s results of operations may be affected by its ability to strategically divest certain businesses.

Generation is actively pursuing opportunities to dispose of businesses, such as its investments in Sithe and Boston Generating, which are either unprofitable or do not advance Generation’s strategic goals. Generation may incur significant costs in divesting these businesses. Generation also may be unable to successfully implement its divestiture strategy of certain businesses for a number of reasons, including an inability to locate appropriate buyers or to negotiate acceptable terms for the transactions. The inability to divest certain businesses could negatively affect Generation’s results of operations. In addition, the amounts that may be realized from a divestiture are subject to fluctuating market conditions that may contribute to pricing and other terms that are materially different than expected and could result in a loss on the sale.

The introduction of new technologies could increase competition within the markets that Generation operates.

While demand for electricity is generally increasing throughout the United States, the rate of construction and development of new, more efficient, electric generating 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.

Generation may make acquisitions that do not achieve the intended financial results.

Generation continues to opportunistically pursue investments that fit its strategic objectives and improve its financial performance. Generation’s future performance will depend in part upon a variety of factors related to these investments, including its ability to successfully integrate them into existing operations. These new investments, as well as existing investments, may not achieve the financial performance that are anticipated.

New Accounting Pronouncements

See Note 1 of the Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.

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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 20, 2004.

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 RMC sets forth risk management policy 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, vice president of strategy, vice president of audit services and officers from each of the business units. The RMC reports to the Exelon Board of Directors on the scope of ComEd’s derivative activities.

Credit Risk

Credit risk for ComEd is managed by ComEd’s credit and collection policies, which are consistent with state regulatory requirements. ComEd is currently obligated to provide service to all electric customers within its respective franchised territories. For the year ended December 31, 2003, ComEd’s ten largest customers represented approximately 2% of its retail electric revenues. ComEd 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.

Midwest Generation. ComEd is a party to various transactions with Midwest Generation, a subsidiary of Edison Mission Energy (EME) and Edison Mission Midwest Holdings (EMMH). Although earlier public filings in 2003 by EME indicated credit issues, a filing in December 2003 indicated that EMMH had secured financing and re-paid its significant current debts. Thus, ComEd’s credit contingency risk associated with Midwest Generation has decreased during the fourth quarter of 2003.

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, 2003, a hypothetical 10% increase in the interest rates associated with variable-rate debt would result in a less than $1 million decrease in pre-tax earnings for 2004.

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, 2003, these interest-rate swaps had an aggregate fair market value of $33 million based on the present value difference between the contract and market rates at December 31, 2003. If these derivative instruments had been terminated at December 31, 2003, this estimated fair value represents the amount that would be paid by 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 decrease in the spot yield at December 31, 2003 is estimated to be $39 million.

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If these derivative instruments had been terminated at December 31, 2003, 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, 2003 is estimated to be $28 million. If these derivative instruments had been terminated at December 31, 2003, this estimated fair value represents the amount to be paid by the counterparties to ComEd.

In 2003, ComEd entered into forward-starting interest-rate swaps in the aggregate notional amount of $440 million to lock in interest-rate levels in anticipation of future financings. The debt issuances that these swaps were hedging were considered probable; therefore, ComEd accounted for these interest-rate swap transactions as hedges. In connection with the 2003 issuances of First Mortgage Bonds, forward-starting interest-rate swaps with an aggregate notional amount of $1,070 million were settled with net cash proceeds to counterparties of $45 million that has been deferred in regulatory assets and is being amortized over the life of the First Mortgage Bonds as a net increase to interest expense. At December 31, 2003, ComEd has settled all of its interest-rate swaps, designated as cash-flow hedges.

Commodity Price Risk

ComEd has 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 to purchase energy from an ARES or the ComEd PPO. Revenues collected from customers electing the PPO include commodity charges at market-based prices and CTC revenues which are calculated to provide the customer with a credit for the market price for electricity. Because the change in revenues from customers electing the PPO is significantly offset by the change in CTC revenues, ComEd does not believe that its exposure to such a market price decrease would be material.

CTC revenues are also collected from customers who elect to purchase energy from an ARES. CTC rates are reset once a year in the spring, and customers can elect to lock in their CTC rates for a one-, two- or three-year term. Based on the current customers who have elected the one-year CTC rates, ComEd has performed a sensitivity analysis to determine the net impact of a 10% increase in the average market price of electricity which would result in a $14 million decrease in CTC revenues. A 10% decrease in market prices would result in a $14 million increase in CTC revenues. The result may be significantly affected if additional customers elect to purchase energy from an ARES or if customers elect to purchase their energy from ComEd.

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 policy 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, vice president of strategy, vice president of audit services and officers from each of the business units. The RMC reports to the Exelon Board of Directors on the scope of Exelon’s derivative activities. As a result of the PPA with Generation and its purchased gas adjustment clause, 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 are consistent with state regulatory requirements. PECO is obligated to provide service to all electric customers within its franchised

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service territories. As a result, PECO has a broad customer base. For the year ended December 31, 2003, PECO’s ten largest customers represented approximately 7% of its retail electric and gas 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 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. 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.

Interest Rate Risk

In 2003, PECO entered into forward-starting interest-rate swaps in the aggregate notional amount of $360 million to lock in interest-rate levels in anticipation of future financings, in connection with the issuance of First and Refunding Mortgage Bonds. The debt issuances that these swaps were hedging were considered probable; therefore, PECO accounted for these interest-rate swap transactions as hedges. PECO settled these swaps for net cash proceeds of $1 million, which was recorded in other comprehensive income and is being amortized over the life of the debt issuance.

PETT 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 $11 million at December 31, 2003. As of December 31, 2003 PETT, a wholly owned subsidiary, was deconsolidated from the financial statements of PECO.

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 policy 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, vice president of strategy, vice president of audit services 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, energy and fossil 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 three years. Generation has an estimated 89% hedge ratio in

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2004 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’s 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 approximately a $32 million decrease in net income. This sensitivity assumes an 89% 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 but 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 one percent of Generation’s owned and contracted supply of electricity. The trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop-loss and value-at-risk limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon’s RMC monitor the financial risks of the power marketing activities.

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 Policies and 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 other comprehensive income (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 years ended December 31, 2003 and 2002. Normal operations and hedging activities represent the marketing of electricity available from Generation’s owned or contracted generation, including ComEd’s 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).


For the year ended December 31, 2003	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 (b)		207			1			208
Changes in valuation techniques and assumptions		—			—			—
Reclassification to realized at settlement of contracts		(223	)		(4	)		(227	)

Total change in unrealized fair value		(16	)		(3	)		(19	)
Realized net settlement of transactions subject to mark-to-market		223			4			227

Total mark-to-market activities gross margin	$	207		$	1		$	208

Accrual activities:
Accrual activities revenue	$	5,187		$	—		$	5,187
Hedge gains reclassified from OCI		2,358			—			2,358

Total revenue – accrual activities		7,545			—			7,545

Purchased power and fuel		2,107			—			2,107
Hedges of purchased power and fuel reclassified from OCI		2,631			—			2,631

Total purchased power and fuel		4,738			—			4,738

Total accrual activities gross margin		2,807			—			2,807

Total gross margin (c)	$	3,014		$	1		$	3,015

(a)	Normal Operations and Hedging Activities only include derivative contracts Power Team enters into to hedge anticipated exposures related to its owned and contracted generation supply, but excludes its owned and contracted generating assets.

(b)	Includes hedge ineffectiveness, recorded in earnings of $1 million.

(c)	Total Gross Margin represents revenue, net of purchased power and fuel expense for Generation.

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For the year ended December 31, 2002	Normal Operations and Hedging Activities (a)			Proprietary Trading			Total
Mark-to-market activities:
Unrealized mark-to-market gain/(loss)
Origination unrealized gain/(loss) at inception	$	—		$	—		$	—
Changes in fair value prior to settlements		26			(29	)		(3	)
Changes in valuation techniques and assumptions		—			—			—
Reclassification to realized at settlement of contracts		(20	)		20			—

Total change in unrealized fair value		6			(9	)		(3	)
Realized net settlement of transactions subject to mark-to-market		20			(20	)		—

Total mark-to-market activities gross margin	$	26		$	(29	)	$	(3	)

Accrual activities:
Accrual activities revenue	$	6,785		$	—		$	6,785
Hedge gains reclassified from OCI		76			—			76

Total revenue – accrual activities		6,861			—			6,861

Purchased power and fuel		4,230			—			4,230
Hedges of purchased power and fuel reclassified from OCI		23			—			23

Total purchased power and fuel		4,253			—			4,253

Total accrual activities gross margin		2,608			—			2,608

Total gross margin (b)	$	2,634		$	(29	)	$	2,605

(a)	Normal Operations and Hedging Activities only include derivative contracts Power Team enters into to hedge anticipated exposures related to its owned and contracted generation supply, but excludes its owned and contracted generating assets.

(b)	Total Gross Margin represents revenue, net of purchased power and fuel expense for Generation.

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The following table provides detail on changes in Generation’s mark-to-market net asset (liability) balance sheet position from January 1, 2002 to December 31, 2003. 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 to earnings and changes in fair value for the hedging activities that are recorded in accumulated other comprehensive income on the Consolidated Balance Sheets.


	Normal Operations and Hedging Activities			Proprietary Trading			Total
Total mark-to-market energy contract net assets at January 1, 2002	$	78		$	14		$	92
Total change in fair value during 2002 of contracts recorded in earnings		26			(29	)		(3	)
Reclassification to realized at settlement of contracts recorded in earnings		(20	)		20			—
Reclassification to realized at settlement from OCI		(53	)		—			(53	)
Effective portion of changes in fair value – recorded in OCI		(210	)		—			(210	)
Purchase/sale of existing contracts or portfolios subject to mark-to-market		11			—			11

Total mark-to-market energy contract net assets (liabilities) at December 31, 2002		(168	)		5			(163	)
Total change in fair value during 2003 of contracts recorded in earnings		206			—			206
Reclassification to realized at settlement of contracts recorded in earnings		(223	)		(4	)		(227	)
Reclassification to realized at settlement from OCI		273			—			273
Effective portion of changes in fair value – recorded in OCI		(305	)		—			(305	)
Purchase/sale of existing contracts or portfolios subject to mark-to-market		—			—			—

Total mark-to-market energy contract net assets (liabilities) at December 31, 2003	$	(217	)	$	1		$	(216	)

The following table details the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of December 31, 2003:


	Normal Operations and Hedging Activities			Proprietary Trading			Total
Current assets	$	319		$	3		$	322
Noncurrent assets		99			1			100

Total mark-to-market energy contract assets		418			4			422

Current liabilities		(502	)		(3	)		(505	)
Noncurrent liabilities		(133	)		—			(133	)

Total mark-to-market energy contract liabilities		(635	)		(3	)		(638	)

Total mark-to-market energy contract net assets (liabilities)	$	(217	)	$	1		$	(216	)

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The following table details the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of December 31, 2002:


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

Total mark-to-market energy contract assets		232			6			238

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

Total mark-to-market energy contract liabilities		(400	)		(1	)		(401	)

Total mark-to-market energy contract net assets (liabilities)	$	(168	)	$	5		$	(163	)

The majority of Generation’s contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter, on-line exchanges. Prices reflect the average of the bid-ask midpoint prices obtained from all sources that Generation believes provide the most liquid market for the commodity. The terms for which such price information is available varies by commodity, region and 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, 2003 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.

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The following table, which presents maturity and source of fair value of mark-to-market energy contract net liabilities, 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 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 either generate or require cash.


	Maturities within																Total Fair Value
	2004			2005			2006			2007			2008		2009 and Beyond		Total Fair Value
Normal Operations, qualifying cash-flow hedge contracts (1):
Actively quoted prices	$	32		$	—		$	—		$	—		$	—	$	—	$	32
Prices provided by other external sources		(219	)		(23	)		(8	)		—			—		—		(250	)

Total	$	(187	)	$	(23	)	$	(8	)	$	—		$	—	$	—	$	(218	)

Normal Operations, other derivative contracts (2):
Actively quoted prices	$	23		$	—		$	—		$	—		$	—	$	—	$	23
Prices provided by other external sources		(26	)		9			5			—			—		—		(12	)
Prices based on model or other valuation methods		7			(5	)		(9	)		(3	)		—		—		(10	)

Total	$	4		$	4		$	(4	)	$	(3	)	$	—	$	—	$	1

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

Total	$	—		$	1		$	—		$	—		$	—	$	—	$	1

Average tenor of proprietary trading portfolio (4)																		1 year

(1)	Mark-to-market gains and losses on contracts that qualify as cash-flow hedges are recorded in other comprehensive income.

(2)	Mark-to-market gains and losses on other non-trading derivative contracts that do not qualify as cash-flow hedges are recorded in earnings.

(3)	Mark-to-market gains and losses on trading contracts are recorded in earnings.

(4)

Following the recommendations of the Committee of Chief Risk Officers, the average tenor of the proprietary trading portfolio measures the average time to collect value for that portfolio. Generation measures the tenor by separating positive and negative mark-to-market values in its proprietary trading portfolio, estimating the mid-point in years for each and then reporting the highest of the two mid-points calculated. In the event that this methodology resulted in significantly different absolute values of the positive and negative cash flow streams, Generation would use the mid-point of the portfolio with the largest cash flow stream as the tenor.

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The table below provides details of effective cash-flow hedges under SFAS No. 133 included in the balance sheet as of December 31, 2003. The data in the table gives an indication of the magnitude of SFAS No. 133 hedges Generation has in place; however, since 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 years ended December 31, 2003 and December 31, 2002, providing insight into the drivers of the changes (new hedges entered into during the period and changes in the value of existing hedges). Information related to energy merchant activities is presented separately from interest-rate hedging activities.


	Total Cash-Flow Hedge Other Comprehensive Income Activity, Net of Income Tax
	Power Team Normal Operations and Hedging Activities			Interest-Rate and Other Hedges			Total Cash Flow Hedges
Accumulated OCI, January 1, 2002	$	47		$	(2	)	$	45
Changes in fair value		(128	)		(3	)		(131	)
Reclassifications from OCI to net income		(33	)		—			(33	)

Accumulated OCI, December 31, 2002		(114	)		(5	)		(119	)
Changes in fair value		(186	)		(8	)		(194	)
Reclassifications from OCI to net loss		167			—			167

Accumulated OCI derivative loss at December 31, 2003	$	(133	)	$	(13	)	$	(146	)

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.

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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 portfolio considered in the one-tailed test. The following table provides the VaR for all proprietary trading positions of Generation as of December 31, 2003.


	Proprietary Trading VaR
95% Confidence level, one-day holding period, one-tailed
Period end	$	—
Average for the period		(0.1	)
High		(0.2	)
Low		—

95% Confidence level, ten-day holding period, two-tailed
Period end	$	(0.1	)
Average for the period		(0.5	)
High		(0.9	)
Low		(0.1	)

99% Confidence level, one-day holding period, two-tailed
Period end	$	—
Average for the period		(0.2	)
High		(0.3	)
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.

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The following tables provide information on Generation’s credit exposure, net of collateral, as of December 31, 2003 and 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 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 as of December 31, 2003	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	$	116	$	—	$	116	1	$	20
Non-investment grade		22		7		15	—		—
No external ratings
Internally rated – investment grade		13		—		13	—		—
Internally rated – non-investment grade		1		—		1	—		—

Total	$	152	$	7	$	145	1	$	20


Rating as of December 31, 2002	Total Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number Of Counterparties Greater than 10% of Net Exposure	Net Exposure Of Counterparties Greater than 10% of Net Exposure
Investment grade	$	156	$	—	$	156	2	$	71
Non-investment grade		17		11		6	—		—
No external ratings
Internally rated – investment grade		27		4		23	4		16
Internally rated – non-investment grade		4		2		2	—		—

Total	$	204	$	17	$	187	6	$	87


	Maturity of Credit Risk Exposure
Rating as of December 31, 2003	Less than 2 Years		2-5 Years		Exposure Greater than 5 Years		Total Exposure Before Credit Collateral
Investment grade	$	101	$	15	$	—	$	116
Non-investment grade		22		—		—		22
No external ratings
Internally rated – investment grade		13		—		—		13
Internally rated – non-investment grade		1		—		—		1

Total	$	137	$	15	$	—	$	152

Dynegy.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. Generation has credit risk associated with Dynegy through Generation’s equity investment in Sithe. Sithe is a 60% owner of the Independence generating station, a 1,028-MW gas-fired facility that has an energy-only long-term tolling agreement with Dynegy, with a related financial swap arrangement. Sithe has entered into a contract to purchase the remaining 40% interest of the Sithe Independence Power Project (Independence) generating station. As of

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December 31, 2003, 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 were unable to fulfill the terms of this agreement, Sithe would be required to impair this financial swap asset. As a 50% owner of Sithe, Generation’s estimated impairment would result in an after-tax reduction of equity earnings of approximately $5 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, Sithe would likely incur a further impairment associated with the Independence plant. Depending upon the timing of Dynegy’s failure to fulfill its obligations and the outcome of any restructuring initiatives, Exelon could realize an after-tax charge of up to $30 million, net of a FIN No. 45 quarantee recorded in connection with Generation’s sale of 50% of Sithe to Reservoir. In the event of a sale of Exelon’s investment in Sithe to a third party, proceeds from the sale could be negatively affected by up to $74 million, which would represent an after-tax loss of up to $43 million.

Additionally, the future economic value of AmerGen’s purchased power arrangement with Illinois Power Company, a subsidiary of Dynegy, could be affected by events related to Dynegy’s financial condition. On February 3, 2004, Dynegy announced an agreement to sell its subsidiary Illinois Power Company to a third party, which, upon closing of the transaction, would reduce Generation’s credit risk associated with Dynegy.

Midwest Generation. Generation is party to various transactions with Midwest Generation, a subsidiary of EME and EMMH. Although earlier public filings in 2003 by EME indicated credit issues, a filing in December 2003 indicated that EMMH had secured financing and re-paid its significant current debts. Thus, Generation’s credit contingency risk associated with Midwest Generation decreased during the fourth quarter of 2003.

Collateral.As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of capacity, energy, fuels and emissions allowances. These contracts either contain express provisions or otherwise permit Generation’s counterparties and Generation to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed to provisions that specify the collateral that must be provided, the obligation to supply the collateral requested will be a function of the facts and circumstances of Generation’s situation at the time of the demand. If Generation can reasonably claim that it is willing and financially able to perform its obligations, it may be possible to successfully argue that no collateral should be posted or that only an amount equal to two or three months of future payments should be sufficient.

ISOs.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 on the spot markets that are operated by the ISOs. In areas where there is no spot market, electricity is purchased and sold solely through bilateral agreements. 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

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conditions. These strategies are employed to achieve a lower cost of capital. As of December 31, 2003, 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 2004.

Under the terms of the Boston Generating Facility, Boston Generating is required to effectively fix the interest rate on 50% of borrowings under the facility through its maturity in 2007. As of December 31, 2003, Boston Generating had entered into interest-rate swap agreements that effectively fixed the interest rate on $861 million of notional principal, or 83% of borrowings outstanding under the Boston Generating credit facility at December 31, 2003. The fair market value exposure of these swaps, designated as cash-flow hedges, was $77 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, 2003 is estimated to be $89 million. If the derivative instruments had been terminated at December 31, 2003, 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, 2003 is estimated to be $65 million. If the derivative instruments had been terminated at December 31, 2003, this estimated fair value represents the amount Generation would pay to the counterparties.

In January 2004, the counterparties terminated the interest-rate swaps with Boston Generating. The total net value of these swaps as of the respective termination dates was $82 million, which is a net payable to the counterparties.

In 2003, Generation entered into forward-starting interest-rate swaps in the aggregate notional amount of $500 million to lock in interest-rate levels in anticipation of future financings. The debt issuances that these swaps are hedging were considered probable; therefore, Generation accounted for these interest-rate swap transactions as hedges. In connection with Generation’s December 2003 issuance of Senior Notes, Generation settled swaps with an aggregate notional amount of $500 million for net cash proceeds of $1 million, which was recorded in other comprehensive income and is being amortized over the life of the debt issuance.

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, 2003, 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 $303 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 Policies and Estimates for information regarding the pension and other postretirement benefit trust assets.

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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 2003, 2002 and 2001; Consolidated Statements of Cash Flows for the years 2003, 2002 and 2001; Consolidated Balance Sheets as of December 31, 2003 and 2002; Consolidated Statements of Changes in Shareholders’ Equity for the years 2003, 2002 and 2001 and Consolidated Statements of Comprehensive Income for the years 2003, 2002 and 2001; and Notes to Consolidated Financial Statements appearing in Exhibit 99-4 to Exelon’s Current Report on Form 8-K dated February 20, 2004.

134

ComEd

Report of Independent Auditors

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, 2003 and 2002 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 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 1 to the consolidated financial statements, ComEd changed its method of accounting for goodwill as of January 1, 2002 and its method of accounting for variable interest entities as of December 31, 2003; and as discussed in Note 10 to the consolidated financial statements, ComEd changed its method of accounting for asset retirement obligations as of January 1, 2003.

PricewaterhouseCoopers LLP

Chicago, Illinois

January 28, 2004

135

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Income


	For the Years Ended December 31,
(in millions)	2003			2002			2001
Operating revenues
Operating revenues	$	5,749		$	6,061		$	6,125
Operating revenues from affiliates		65			63			81

Total operating revenues		5,814			6,124			6,206

Operating expenses
Purchased power and fuel		22			26			14
Purchased power from affiliate		2,479			2,559			2,656
Operating and maintenance		957			828			846
Operating and maintenance from affiliates		136			136			135
Depreciation and amortization		386			522			665
Taxes other than income		267			287			296

Total operating expenses		4,247			4,358			4,612

Operating income		1,567			1,766			1,594

Other income and deductions
Interest expense		(423	)		(480	)		(555	)
Interest expense to affiliates		—			(4	)		(10	)
Distributions on mandatorily redeemable preferred securities		(26	)		(30	)		(30	)
Interest income from affiliates		25			31			79
Other, net		24			13			35

Total other income and deductions		(400	)		(470	)		(481	)

Income before income taxes and cumulative effect of a change in accounting principle		1,167			1,296			1,113
Income taxes		465			506			506

Income before cumulative effect of a change in accounting principle		702			790			607
Cumulative effect of a change in accounting principle (net of income taxes of $0)		5			—			—

Net income	$	707		$	790		$	607

See Notes to Consolidated Financial Statements

136

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(in millions)	2003			2002			2001
Cash flows from operating activities
Net income	$	707		$	790		$	607
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization		386			522			665
Cumulative effect of a change in accounting principle (net of income taxes)		(5	)		—			—
Deferred income taxes and amortization of investment tax credits		7			118			14
Provision for uncollectible accounts		46			50			42
Gain on sale of investment		(3	)		—			—
Reversal of provision for revenue refunds		—			—			(15	)
Midwest independent system operator exit fees		—			—			(36	)
Other operating activities		64			103			45
Changes in assets and liabilities:
Accounts receivable		57			(72	)		76
Inventories		14			(9	)		16
Other current assets		(17	)		1			2
Accounts payable, accrued expenses and other current liabilities		(1	)		135			149
Change in receivables and payables to affiliates		(155	)		117			(274	)
Pension and non-pension postretirement benefits obligation payments		(48	)		(68	)		6
Other noncurrent assets and liabilities		(104	)		(23	)		(36	)

Net cash flows provided by operating activities		948			1,664			1,261

Cash flows from investing activities
Capital expenditures		(712	)		(780	)		(869	)
Investment in affiliate money pool		(405	)		—			—
Notes receivable from affiliates		213			14			400
Change in restricted cash		(15	)		(24	)		19
Proceeds from sale of investments		5			—			—
Other investing activities		21			7			11

Net cash flows used in investing activities		(893	)		(783	)		(439	)

Cash flows from financing activities
Issuance of long-term debt, net of issuance costs		1,497			752			—
Retirement of long-term debt		(1,425	)		(1,551	)		(542	)
Issuance of mandatorily redeemable preferred securities		200			—			—
Retirement of mandatorily redeemable preferred securities		(200	)		—			—
Change in short-term debt		(71	)		71			—
Dividends paid on common stock		(401	)		(470	)		(483	)
Contributions from parent		451			344			125
Settlement of cash-flow hedges		(45	)		(10	)		—
Other financing activities		(43	)		(24	)		(40	)

Net cash flow used in financing activities		(37	)		(888	)		(940	)

Increase (decrease) in cash and cash equivalents		18			(7	)		(118	)
Cash and cash equivalents at beginning of period		16			23			141

Cash and cash equivalents at end of period	$	34		$	16		$	23

See Notes to Consolidated Financial Statements

137

Commonwealth Edison Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(in millions)	2003			2002
Assets

Current assets
Cash and cash equivalents	$	34		$	16
Restricted cash		20			65
Accounts receivable, net
Customer		683			782
Other		68			72
Inventories, at average cost		43			65
Deferred income taxes		6			20
Receivables from affiliates		428			15
Other		31			14

Total current assets		1,313			1,049

Property, plant and equipment, net		9,096			8,689

Deferred debits and other assets
Investments		36			42
Investments in affiliates		59			—
Goodwill		4,719			4,916
Receivables from affiliates		2,271			1,300
Other		457			320

Total deferred debits and other assets		7,542			6,578

Total assets	$	17,951		$	16,316

Liabilities and shareholders’ equity

Current liabilities
Commercial paper	$	—		$	71
Long-term debt due within one year		236			698
Long-term debt to ComEd Transitional Funding Trust due within one year		317			—
Accounts payable		170			201
Accrued expenses		540			538
Payables to affiliates		207			416
Customer deposits		78			81
Other		9			18

Total current liabilities		1,557			2,023

Long-term debt		4,167			5,268
Long-term debt to ComEd Transitional Funding Trust		1,359			—
Long-term debt to affiliates		361			—

Deferred credits and other liabilities
Deferred income taxes		1,672			1,650
Unamortized investment tax credits		48			51
Pension obligation		—			91
Non-pension postretirement benefits obligation		190			138
Payables to affiliates		28			224
Regulatory liabilities		1,891			486
Other		336			297

Total deferred credits and other liabilities		4,165			2,937

Total liabilities		11,609			10,228

Commitments and contingencies
Mandatorily redeemable preferred securities		—			330

Shareholders’ equity
Common stock		1,588			1,588
Preference stock		7			7
Other paid in capital		4,115			4,239
Receivable from parent		(250	)		(615	)
Retained earnings		883			577
Accumulated other comprehensive income (loss)		(1	)		(38	)

Total shareholders’ equity		6,342			5,758

Total liabilities and shareholders’ equity	$	17,951		$	16,316

See Notes to Consolidated Financial Statements

138

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Changes in Shareholders’ Equity


(in millions)	Common Stock			Preferred and Preference Stock		Other Paid In Capital			Receivable from Parent			Retained Earnings Unappropriated			Retained Earnings Appropriated		Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total Shareholders’ Equity
Balance, December 31, 2000	$	2,678		$	7	$	5,388		$	—		$	133		$	—	$	—		$	(2,023	)	$	6,183
Net income		—			—		—			—			607			—		—			—			607
Receivable from parent		—			—		1,062			(1,062	)		—			—		—			—			—
Repayment of receivable from parent		—			—		—			125			—			—		—			—			125
Retirement of treasury shares		(630	)		—		(1,393	)		—			—			—		—			2,023			—
Merger fair value adjustments		—			—		24			—			—			—		—			—			24
Corporate restructuring		—			—		(24	)		—			—			—		—			(1,344	)		(1,368	)
Common stock dividends		—			—		—			—			(483	)		—		—			—			(483	)
Other comprehensive income, net of income taxes of $(1)		—			—		—			—			—			—		(5	)		—			(5	)

Balance, December 31, 2001		2,048			7		5,057			(937	)		257			—		(5	)		(1,344	)		5,083
Net income		—			—		—			—			790			—		—			—			790
Repayment of receivable from parent		—			—		—			322			—			—		—			—			322
Allocation of tax benefit from parent		—			—		28			—			—			—		—			—			28
Retirement of treasury shares		(460	)		—		(884	)		—			—			—		—			1,344			—
Merger fair value adjustments		—			—		38			—			—			—		—			—			38
Common stock dividends		—			—		—			—			(470	)		—		—			—			(470	)
Other comprehensive income, net of income taxes of $(23)		—			—		—			—			—			—		(33	)		—			(33	)

Balance, December 31, 2002		1,588			7		4,239			(615	)		577			—		(38	)		—			5,758
Net income		—			—		—			—			707			—		—			—			707
Repayment of receivable from parent		—			—		—			365			—			—		—			—			365
Allocation of tax benefit from parent		—			—		86			—			—			—		—			—			86
Appropriation of Retained Earnings for future dividends		—			—		—			—			(709	)		709		—			—			—
Common stock dividends		—			—		—			—			(401	)		—		—			—			(401	)
Adoption of SFAS No. 143		—			—		(210	)		—			—			—		—			—			(210	)
Other comprehensive income, net of income taxes of $23		—			—		—			—			—			—		37			—			37

Balance, December 31, 2003	$	1,588		$	7	$	4,115		$	(250	)	$	174		$	709	$	(1	)	$	—		$	6,342

See Notes to Consolidated Financial Statements

139

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Comprehensive Income


	For the Years Ended December 31,
(in millions)	2003		2002			2001
Net income	$	707	$	790		$	607
Other comprehensive income (loss)
Cash-flow hedge adjustment, net of income taxes of $21, $(21) and $0, respectively	$	31	$	(30	)	$	(1	)
Foreign currency translation adjustment, net of income taxes of $0 and $0, respectively		3		—			(1	)
Unrealized gain (loss) on marketable securities, net of income taxes of $2, $(1), and $(1), respectively		3		(3	)		(3	)

Total other comprehensive income (loss)		37		(33	)		(5	)

Total comprehensive income	$	744	$	757		$	602

See Notes to Consolidated Financial Statements

140

Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, unless otherwise noted)

1. Significant Accounting Policies and Changes in Accounting Estimates

Description of Business

Commonwealth Edison Company (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’s retail service territory has an area of approximately 11,300 square miles and an estimated population of eight million. The service territory includes the City of Chicago, an area of about 225 square miles with an estimated population of three million. ComEd has approximately 3.6 million customers.

Basis of Presentation

On October 20, 2000, Exelon Corporation (Exelon) became the parent corporation of PECO Energy Company (PECO) and ComEd as a result of the completion of the transactions contemplated by an Agreement and Plan of Exchange and Merger, as amended (Merger), among PECO, Unicom Corporation, and Exelon. As a result of the Merger, ComEd, a regulated electric utility, is a principal subsidiary of Exelon, which owns 99.9% of ComEd’s common stock. During January 2001, Exelon undertook a corporate restructuring to separate its generation and other competitive businesses from its regulated energy delivery businesses at ComEd and PECO. As part of the restructuring, the generation-related operations and assets and liabilities of ComEd were transferred to Exelon Generation Company, LLC (Generation). Additionally, certain operations and assets and liabilities of ComEd were transferred to Exelon Business Services Company (BSC). As a result, effective January 1, 2001, the operations of ComEd consist of its retail electricity distribution and transmission business in northern Illinois.

The consolidated financial statements include the accounts of ComEd, Commonwealth Edison Company of Indiana, Inc., Edison Development Canada Inc., Edison Finance Partnership, Commonwealth Research Corporation, and Edison Development Company. All intercompany transactions have been eliminated. Effective December 31, 2003 the accounts of ComEd Financing II, ComEd Financing III, ComEd Funding LLC (ComEd Funding) and ComEd Transitional Funding Trust (ComEd Funding Trust) are no longer consolidated. The accounts of ComEd Funding and ComEd Funding Trust, which are Special Purpose Entities (SPEs), 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.

Reclassifications

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

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States (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, asset and goodwill impairment, environmental costs, allowance for doubtful accounts, fixed asset depreciation, taxes and pension and other postretirement costs.

141

Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

Accounting for the Effects of Regulation

ComEd is regulated by 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 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,” (SFAS No. 71) which requires ComEd to record in the financial statements the effects of the rate regulation. Use of SFAS No. 71 is applicable to the utility operations of ComEd that meet the following criteria: (1) third-party regulation of rates; (2) cost-based rates; and (3) a reasonable assumption that all costs will be recoverable from customers through rates. ComEd believes that it is probable that regulatory assets and liabilities associated with these operations will be recovered or settled. If a separable portion of ComEd’s business no longer meets the provisions of SFAS No. 71, ComEd would be required to eliminate the financial statement effects of regulation for that portion.

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.

Variable Interest Entities

The FASB issued FASB Interpretation (FIN) No. 46 “Consolidation of Variable Interest Entities” in January 2003 and issued its revision in FASB Interpretation No. 46-R “Consolidation of Variable Interest Entities” (FIN No. 46-R) in December 2003, which addressed the requirements for consolidating certain variable interest entities. FIN No. 46-R was effective December 31, 2003 for ComEd’s variable interest entities that are considered to be special-purpose entities. FIN No. 46-R applies to all other variable interest entities as of

March 31, 2004.

As of December 31, 2003, the financing trusts of ComEd (ComEd Financing II, ComEd Financing III, ComEd Funding, and ComEd Funding Trust) were no longer consolidated within the financial statements of ComEd pursuant to the provisions of FIN No. 46-R. Amounts of $2.0 billion owed to these financing trusts were recorded as debt to affiliates and debt to ComEd Transitional Funding Trust within the Consolidated Balance Sheet. This change in presentation had no significant impact on the results of operations or financial position of ComEd. In accordance with FIN No. 46-R, prior periods have not been restated.

Instruments with Characteristics of Both Liabilities and Equity

In May 2003, the FASB issued SFAS No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (SFAS No. 150). SFAS No. 150 requires that certain instruments that have characteristics of both liabilities and equity be classified as liabilities in the statement of financial position. SFAS No. 150 affects the accounting for three types of freestanding financial instruments: mandatorily redeemable shares, instruments that do or may require the issuer to buy some of its shares in exchange for cash or other assets, and obligations that can be settled with shares, the monetary value of which is fixed, tied solely or predominately to a variable such as a market index, or varies inversely with the value of the issuer’s shares.

Most of the guidance of SFAS No. 150 was effective for all financial instruments entered into or modified after May 31, 2003, and otherwise was effective for ComEd as of July 1, 2003. As a result of the implementation of FIN No. 46-R and the subsequent deconsolidated of certain financing subsidiaries of ComEd, the implementation of SFAS No. 150 had no impact for the year ended December 31, 2003 on ComEd’s financial position or results of operations.

142

Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

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 3 – Accounts Receivable for further discussion.

Stock-Based Compensation

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). ComEd adopted the additional disclosure requirements of SFAS No. 148 in 2002 and continues to account for its stock-compensation plans under the disclosure-only provision 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, 2003, 2002 and 2001:


	2003		2002		2001
Net income – as reported	$	707	$	790	$	607
Deduct: Total stock-based compensation expense determined under fair-value method for all awards, net of income taxes		5		13		10

Pro forma net income	$	702	$	777	$	597

Income Taxes

Deferred Federal and state income taxes are provided on all significant temporary differences between the book basis and the tax basis of assets and liabilities and for 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 consolidated Federal and state income tax returns with Exelon. Income taxes of the Exelon consolidated group are allocated to ComEd based on the separate return method (see Note 9 – Income Taxes).

ComEd is a party to an agreement (the “Tax Sharing Agreement”) that provides for the allocation of consolidated tax liabilities. The Tax Sharing Agreement generally provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to other members. That allocation is treated as a contribution to the capital of the party receiving the benefit.

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 life of new debt issued to finance the debt redemption consistent with rate recovery for ratemaking purposes.

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.

Cash and Cash Equivalents

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

143

Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

Restricted Cash

As of December 31, 2003, ComEd’s restricted cash relates to proceeds from a pollution control bond offering in December 2003 which were applied to redeem pollution control bonds that matured in January 2004. See Note 19 – Subsequent Events. Prior to the adoption of FIN No. 46-R, the restricted cash of ComEd Funding Trust was included in ComEd’s Consolidated Balance Sheets. As of December 31, 2002, the restricted cash reflected escrowed cash to be applied to the principal and interest payments on the debt issued by ComEd Funding Trust.

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. At December 31, 2003 and 2002, 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 for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.”

Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation and removal costs reduce the related regulatory liability in accordance with the provisions of SFAS No. 71. See Note 16 – Supplemental Financial Information. For unregulated property, the cost and accumulated depreciation of the property, plant and equipment retired or otherwise disposed of are removed from the related accounts and included in the determination of any gain or loss on disposition. See Note 4 – Property, Plant and Equipment.

Capitalized Software Costs

Costs incurred during the application development stage of software projects that are developed or obtained for internal use are capitalized. At December 31, 2003 and 2002, capitalized software costs totaled $222 million and $192 million, respectively, and $72 million and $39 million in accumulated amortization, respectively. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed 10 years. Certain capitalized software is being amortized over 15 years pursuant to regulatory approval. During 2003, 2002 and 2001, ComEd amortized capitalized software costs of $33 million, $23 million, and $14 million, respectively.

Depreciation and Amortization

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	2003		2002		2001
Electric — transmission and distribution	3.20	%	3.74	%	5.20	%
Other property and equipment	7.14	%	7.92	%	5.95	%

144

Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

Amortization of regulatory assets is provided over the recovery period specified in the related legislation or regulatory agreement. Goodwill associated with the Merger was amortized on a straight-line basis over 40 years in 2001. Accumulated amortization of goodwill was $149 million 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 Note 5 – Goodwill.

Allowance for Funds Used During Construction

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 $15 million, $18 million, and $17 million in 2003, 2002 and 2001, 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 within the Consolidated Statements of Income. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.

Goodwill

Goodwill represents the excess of the purchase price paid over the estimated fair value of the assets acquired and liabilities assumed in the acquisition of a business. As of January 1, 2002, ComEd adopted SFAS No. 142. Pursuant to SFAS No. 142, goodwill is no longer amortized but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would reduce the fair value of a reporting unit below its carrying value. Prior to January 1, 2002, goodwill was amortized using the straight-line method over its estimated period of benefit. Goodwill associated with the Merger was amortized on a straight-line basis over 40 years in 2001. See Note 5 – Goodwill.

Derivative Financial Instruments

ComEd accounts for derivative financial instruments pursuant to 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 instrument are recognized in earnings unless specific hedge accounting criteria are met, in which case those changes are recorded in other comprehensive income.

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.

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 liability measured at their fair value through earnings, with special accounting permitted for certain qualifying hedges.

145

Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

In connection with Exelon’s Risk Management Policy, ComEd enters into derivatives to effectively manage its exposure to fluctuations in interest rates, including interest rate fluctuations 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.

New Accounting Pronouncements

Through Exelon’s postretirement benefit plans, ComEd provides retirees with prescription drug coverage. On December 8, 2003 the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Prescription Drug Act) was enacted. The Prescription Drug Act introduced a prescription drug benefit under Medicare as well as a Federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. In response to the enactment of the Prescription Drug Act, the FASB issued FASB Staff Position (FSP) FAS 106-1 (FSP FAS 106-1) in January 2004, which permits a plan sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer the accounting for the effects of the Prescription Drug Act. Exelon has made the one-time election allowed by FSP FAS 106-1. Thus, ComEd’s financial statements and Note 11 – Retirement Benefits do not reflect the effects of the Prescription Drug Act on ComEd’s allocated portion Exelon’s postretirement plans. Exelon is evaluating what impact the Prescription Drug Act will have on its postretirement benefit plans and whether it will be eligible for a Federal subsidy beginning in 2006. Specific authoritative guidance on the accounting for the Federal subsidy is pending, and that guidance, when issued, could require ComEd to change previously reported information.

As discussed above, FIN No. 46-R was effective December 31, 2003 for ComEd’s variable interest entities that are considered to be special-purpose entities. FIN No. 46-R applies to all other variable interest entities as of March 31, 2004. ComEd continues to review other entities with which ComEd and its subsidiaries have business arrangements to determine if those entities are variable interest entities under FIN No. 46-R and, if so, whether consolidation of these entities will be required as of March 31, 2004.

2. Regulatory Issues

Delivery service rates. On March 3, 2003, ComEd entered into and the ICC subsequently entered orders to implement an agreement (Agreement) with various Illinois retail market participants and other interested parties that settled, among other things, delivery service rates and the market value index proceeding and facilitates competitive service declarations for large-load customers and an extension of the purchased power agreement (PPA) with Generation. The effect of the Agreement is lower competitive transition charge (CTC) collections that ComEd charges customers who take electricity from an alternative retail electric supplier (ARES) or under the power purchase option (PPO) through 2006. The Agreement also allows customers to lock in current CTC charges for multiple years. A non-party to the Agreement has appealed one of the ICC’s orders which, if ultimately successful, may impact the Agreement on a going-forward basis.

The annual market price adjustments to the CTC effective in June 2002 and the impacts of the Agreement in June 2003 had the effect of significantly increasing the CTC charge in June 2002, and subsequently significantly reducing the CTC charge in June 2003. In 2003 and 2002, ComEd collected $304 million and $306 million in CTC revenues, respectively. Based on the changes in the CTC as part of the Agreement and on current assumptions about the competitive price of delivered energy and customers’ choice of electric supplier, ComEd estimates that CTC revenue will be approximately $180 million to $200 million in each of the years 2004 through 2006.

146

Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

In 2003, ComEd recorded a charge to earnings associated with the required funding of specified programs and initiatives associated with the Agreement of $51 million (before income taxes) on a present value basis. This amount was 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 charge of $51 million and the credit of $10 million were recorded in operating and maintenance expense and the reversal of the $12 million reserve was recorded in other, net within ComEd’s Consolidated Statements of Income. The net charge for these items was $29 million (before income taxes). In accordance with the Agreement, ComEd made payments of $23 million during 2003.

Customer Choice. All ComEd’s retail customers are eligible to choose an ARES and non-residential customers can also elect the PPO that allows the purchase of electric energy from ComEd at market-based prices. As of December 31, 2003, 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, 2003, approximately 20,300 non-residential customers, representing approximately 31% 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.

Competitive Service Declarations. On November 14, 2002, the ICC allowed ComEd, by operation of law, to revise its provider of last resort obligation to be the back-up energy supplier at market based rates for customers with energy demands of at least three megawatts (MWs). About 370 of ComEd’s largest energy customers are affected, representing an aggregate supply obligation or load of approximately 2,500 MWs. These customers accounted for 10% of ComEd’s 2003 MWh deliveries. These customers will not have a right to take bundled service after June 2006 or to come back to bundled rates if they choose an alternative supplier. The parties to the Agreement have committed, if specified market conditions exist, not to oppose a process to be initiated in June 2004 or thereafter for achieving a similar competitive declaration for customers having energy demands of one to three MWs.

On March 28, 2003, the ICC approved changes to ComEd’s 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. An appeal to each of the ICC’s orders is pending and ComEd cannot predict the outcome of those appeals.

ComEd cannot predict the long-term impact of customer choice on its result of operations.

Rate Reductions and Return on Common Equity Threshold. The Illinois restructuring legislation as amended required a 15% residential base rate reduction effective August 1, 1998 and an additional 5% residential base rate reduction effective October 1, 2001. In addition, a base rate freeze, reflecting the residential base rate reductions, is in effect through 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 two-year average of the earned return on common equity of a utility through December 31, 2006 exceeds an established threshold, one-half of the excess earnings must be refunded to customers. The threshold rate of return on common equity is based on a two-year average of the Monthly Treasury Bond Long-Term Average Rates (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 GAAP and reflect the amortization of regulatory assets. As a result of the Illinois legislation, at December 31, 2003, ComEd had a regulatory asset with an unamortized balance of $131 million that it expects to fully recover and amortize by the end of 2006. ComEd did not trigger the earnings sharing provision in 2001, 2002 or 2003 and does not currently expect to trigger the earnings sharing provisions in the years 2004 through 2006.

147

Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

Nuclear Decommissioning Costs.In connection with the transfer of ComEd’s nuclear generating stations to Generation, the ICC permitted ComEd to recover $73 million per year from retail customers for decommissioning for the years 2001 through 2004 and, depending upon the portion of the output from those stations taken by ComEd, up to $73 million annually in 2005 and 2006. Subsequent to 2006, there will be no further recoveries of decommissioning costs from customers. Any surplus funds after a nuclear station is decommissioned must be refunded to ComEd’s customers. Amounts collected from customers are remitted to Generation. See Note 10 – Nuclear Decommissioning.

Open Access Transmission Tariff. On November 10, 2003, the FERC issued an order allowing ComEd to put into effect beginning April 12, 2004, subject to refund and rehearing, new transmission rates designed to reflect nearly $500 million of infrastructure investments made since 1998. However, because of the Illinois retail rate freeze and the method for calculating CTCs, the increase is not expected to significantly increase operating revenues. ComEd is unable to predict the ultimate outcome of the associated rehearing or settlement negotiations.

3. Accounts Receivable

Customer accounts receivable at December 31, 2003 and 2002 included unbilled operating revenues of $225 million and $250 million, respectively. The allowance for uncollectible accounts at December 31, 2003 and 2002 was $16 million and $23 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.

4. Property, Plant and Equipment

A summary of property, plant and equipment by classification as of December 31, 2003 and 2002 is as follows:


	2003		2002
Electric — transmission & distribution	$	8,297	$	7,671
Construction work in progress		365		373
Other property, plant and equipment		1,205		1,098

Total property, plant and equipment		9,867		9,142
Less accumulated depreciation		771		453

Property, plant and equipment, net	$	9,096	$	8,689

ComEd’s depreciation expense, which is included in cost of service for rate purposes, includes an estimated cost of dismantling and removing plant from service upon retirement. Beginning in 2003, in accordance with regulatory accounting practice, collections for future removal costs are recorded as a regulatory liability. Prior periods have been reclassified for comparative purposes. For more information, see Note 16 – Supplemental Financial Information.

Effective July 1, 2002, ComEd decreased 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 was $96 million.

148

Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

5. Goodwill

As of December 31, 2003 and 2002, ComEd had recorded goodwill of approximately $4.7 billion and $4.9 billion, respectively. The changes in the carrying amount of goodwill for the years ended December 31, 2002 and 2003 were as follows:


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

Balances as of January 1, 2003		4,916
Adoption of SFAS No. 143:(a)
Reduction of asset retirement obligation		(210	)
Cumulative effect of change in accounting principle		5
Resolution of certain tax matters		8

Balances as of December 31, 2003	$	4,719

(a)	See Note 10—Nuclear Decommissioning.

Effective January 1, 2002, ComEd adopted SFAS No. 142. Pursuant to SFAS No. 142, goodwill is no longer amortized; however, goodwill is subject to an assessment for impairment at least annually, or more frequently, if events or circumstances indicate that goodwill might be impaired. The impairment assessment is performed using a two-step, fair-value based test. The first step compares the fair value of the 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 estimated 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.

ComEd performed impairment assessments upon adoption of SFAS No. 142 on January 1, 2002, and annually as of November 1, 2002 and 2003, and has determined in each case that its goodwill was not impaired.

In its assessments to estimate the fair value of the ComEd reporting unit, ComEd used a probability-weighted, discounted cash flow model with multiple scenarios. The determination of the fair value is dependent on many sensitive, interrelated and uncertain variables including changing interest rates, utility sector market performance, ComEd’s capital structure, market power prices, post-2006 rate regulatory structures, operating and capital expenditure requirements and other factors. Changes in these variables or in how they interrelate could result in a future impairment of goodwill at ComEd, which could be material. In addition, based on certain anticipated reductions to cash flows subsequent to ComEd’s regulatory transition period (primarily CTCs), ComEd believes there is a reasonable possibility that goodwill will be impaired at ComEd in 2004 or future years, and such impairment may be significant. The actual timing and amounts of goodwill impairments in future years, if any, will depend on the variables discussed above.

Under Illinois statute, any impairment of goodwill has no impact on the determination of the cap on ComEd’s allowed equity return during the electricity industry restructuring transition period through 2006. See Note 2 – Regulatory Issues for further discussion of ComEd’s earnings provisions.

149

Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

6. Severance Accounting

Exelon provides severance and health and welfare benefits to terminated employees pursuant to pre-existing severance plans primarily based upon each individual employee’s years of service with Exelon and compensation level. Exelon accounts for its ongoing severance plans in accordance with SFAS No. 112, “Employer’s Accounting for Postemployment Benefits, an amendment of FASB Statements No. 5 and 43” (SFAS No. 112) and SFAS No. 88, “Employer’s Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” and accrues amounts associated with severance benefits that are considered probable and that can be reasonably estimated.

As part of the implementation of Exelon’s new business model referred to as The Exelon Way, during 2003, ComEd identified 729 positions, including professional, managerial and union employees, for elimination by the end of 2004. ComEd recorded a charge for salary continuance severance of $61 million during 2003, which represented salary continuance severance costs that were probable and could be reasonably estimated as of December 31, 2003. During 2003, ComEd recorded a charge of $28 million associated with special health and welfare severance benefits offered through The Exelon Way. In addition to cash and health and welfare severance benefits, ComEd incurred curtailment costs associated with pension and postretirement benefit plans of $48 million as a result of personnel reductions due to The Exelon Way. In total, ComEd recorded charges of $137 million in 2003 associated with The Exelon Way. See Note 11 – Retirement Benefits for a description of the curtailment charges for the pension and postretirement benefit plans.

ComEd based its estimate of the number of positions to be eliminated on management’s current plans and its ability to determine the appropriate staffing levels to effectively operate the business. ComEd may incur further severance costs associated with The Exelon Way if additional positions are identified for elimination. These costs will be recorded in the period in which the costs can be reasonably estimated.

The following table details ComEd’s total salary continuance severance expense recorded as an operating and maintenance expense within the Consolidated Statements of Income. During 2002 and 2001, no amounts were recorded as severance expense.


Salary continuance severance charges
Expense recorded - 2003	$	61
Expense recorded - 2002		—
Expense recorded - 2001		—

The following table provides a roll forward of ComEd’s salary continuance severance obligation from January 1, 2002 through December 31, 2003. The salary continuance severance obligation as of January 1, 2002 and amounts paid in 2002 relate to severance associated with the Merger.


Salary continuance severance obligation
Balance as of January 1, 2002	$	64
Severance charges recorded		—
Cash payments		(41	)
Other adjustments		(8	)

Balance as of January 1, 2003	$	15
Severance charges recorded		61
Cash payments		(21	)

Balance as of December 31, 2003	$	55

150

Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

7. Notes Payable and Short-Term Debt


	2003			2002			2001
Average borrowings	$	4		$	14		—
Maximum borrowings outstanding		123			146		—
Average interest rates, computed on a daily basis		1.47	%		1.75	%	—
Average interest rates, at December 31		—			1.69	%	—

In October 2003, Exelon, ComEd, PECO and Generation replaced their $1.5 billion bank unsecured revolving credit facility with a $750 million 364-day unsecured revolving credit agreement and a $750 million 3-year unsecured revolving credit agreement with a group of banks. Both revolving credit agreements are used principally to support the commercial paper programs at Exelon, ComEd, PECO and Generation and to issue letters of credit. The 364-day agreement also includes a term-out option provision that allows a borrower to extend the maturity of revolving credit borrowings outstanding at the end of the 364-day period for one year.

At December 31, 2003, ComEd’s aggregate sublimit under the credit agreements was $100 million. Sublimits under the credit agreements can change upon written notification to the bank group. ComEd had approximately $80 million of unused bank commitments under the credit agreements at December 31, 2003. ComEd did not have any commercial paper outstanding at December 31, 2003. At December 31, 2002, ComEd had $123 million of commercial paper outstanding of which $52 million had been classified as long-term debt under the provisions of SFAS No. 6, “Classification of Short-Term Obligations Expected to be Refinanced” (SFAS No. 6). Interest rates on the advances under the credit agreements are based on either the London Interbank Offering Rate or prime plus an adder based on the credit rating of the borrower as well as the total outstanding amounts under the agreements at the time of borrowing. The maximum adder would be 175 basis points.

151

Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

8. Long-Term Debt


	December 31, 2003		December 31,
	Rates	Maturity Date	2003			2002
Securitized long-term debt (e)
ComEd Transitional Trust Notes Series 1998-A:			$	—		$	2,040
Other long-term debt
First and Refunding Mortgage Bonds (a) (b):
Fixed rates	3.70%-9.875%	2004-2033		3,311			2,612
Floating rates	1.07%-1.30%	2013-2020		252			100
Notes payable
Fixed rates	6.40%-9.20%	2004-2018		816			816
Floating rates				—			250
Pollution control bonds:
Fixed rates				—			42
Floating rates				—			92
Sinking fund debentures	3.125%-4.75%	2004-2011		17			20
Commercial paper (c)				—			52

Total long-term debt (d)				4,396			6,024
Unamortized debt discount and premium, net				(26	)		(99	)
Fair-value hedge carrying value adjustment, net				33			41
Due within one year				(236	)		(698	)

Long-term debt			$	4,167		$	5,268

Long-term debt to affiliates (e)
Subordinated debentures to ComEd Financing II (f)	8.50%	2027	$	155		$	—
Subordinated debentures to ComEd Financing III (f)	6.35%	2033		206			—
Payable to ComEd Transitional Funding Trust (f)	5.44%-5.74%	2004-2008		1,676			—

Total long-term debt to affiliates (f)				2,037			—
Due within one year				(317	)		—

Long-term debt to affiliates			$	1,720		$	—

(a)	Utility plant of ComEd is subject to the liens of its mortgage indenture.

(b)	Includes pollution control bonds collateralized by first mortgage bonds issued under ComEd’s mortgage indenture.

(c)	Classified as long-term at December 31, 2002 since it was refinanced with long-term debt in January 2003.

(d)	Long-term debt maturities in the period 2004 through 2008 and thereafter are as follows:


2004	$	236
2005		462
2006		427
2007		152
2008		492
Thereafter		2,627

Total	$	4,396

(e)	Effective December 31, 2003, ComEd Financing II, ComEd Financing III and ComEd Funding Trust were deconsolidated from the financial statements of ComEd in conjunction with the adoption of FIN No. 46-R.

152

Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

Amounts owed to these financing trusts are recorded as debt to affiliates within the Consolidated Balance Sheets.

(f)	Long-term debt to affiliates maturities in the period 2004 through 2008 and thereafter are as follows:


2004	$	317
2005		340
2006		340
2007		340
2008		340
Thereafter		360

Total	$	2,037

During 2003, the following long-term debt was issued:


Type	Rate	Maturity	Amount
First Mortgage Bonds	4.70%	April 15, 2015	$	395
First Mortgage Bonds	3.70%	February 1, 2008		350
First Mortgage Bonds	5.875%	February 1, 2033		350
First Mortgage Bonds	4.74%	August 15, 2010		250
Pollution Control Revenue Bonds (b)	Variable	March 1, 2020		50
Pollution Control Revenue Bonds (b)	Variable	November 1, 2019		42
Pollution Control Revenue Bonds (b)	Variable	May 15, 2017		40
Pollution Control Revenue Bonds (a)(b)	Variable	January 15, 2014		20

Total issuances			$	1,497

(a)	As of December 31, 2003, the proceeds from the issuance of these pollution control revenue bonds were held in escrow for the redemption of pollution control revenue bonds in January 2004. The proceeds are included in restricted cash in ComEd’s Consolidated Balance Sheets.

(b)	These pollution control bonds are collateralized by first mortgage bonds issued under ComEd’s mortgage indenture.

During 2003, payments were made on the following long-term debt:


Type	Rate	Maturity	Amount
Commercial paper classified as long-term debt	1.69%	2003	$	52
First Mortgage Bonds	8.375%	February 15, 2023		236
First Mortgage Bonds	8.00%	April 15, 2023		160
First Mortgage Bonds	7.75%	July 15, 2023		150
First Mortgage Bonds	6.625%	July 15, 2003		100
Pollution Control Revenue Bonds	Variable	March 1, 2009		50
Pollution Control Revenue Bonds	5.875%	May 15, 2007		42
Pollution Control Revenue Bonds	Variable	October 15, 2014		42
Medium term notes	Variable	September 30, 2003		250
Sinking fund debentures	3.125%-4.740%	2003		3
ComEd Transitional Funding Trust Notes	5.390%-5.44%	2003		340

Total payments			$	1,425

153

Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

Prepayment premiums of $21 million and $24 million and net unamortized premiums, discounts and debt issuance expenses of $38 million and $3 million associated with the early retirement of debt in 2003 and 2002, 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.

See Note 12 – Fair Value of Financial Assets and Liabilities for additional information regarding interest-rate swaps. See Note 13 – Preferred Securities of Subsidiaries for additional information regarding mandatorily redeemable preferred securities and preferred stock.

9. Income Taxes

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


	For the Year Ended December 31,
	2003			2002			2001
Included in operations:
Federal
Current	$	362		$	308		$	400
Deferred		19			110			16
Investment tax credit, net		(3	)		(4	)		(4	)
State
Current		96			80			92
Deferred		(9	)		12			2

	$	465		$	506		$	506

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


	For the Year Ended December 31,
	2003		2002		2001
U.S. Federal statutory rate	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
Plant basis differences	(0.2	)	(1.3	)	0.3
State income taxes, net of Federal income tax benefit	4.8		4.6		5.5
Amortization of goodwill	—		—		4.0
Amortization of investment tax credit	(0.3	)	(0.3	)	(0.4	)
Amortization of regulatory asset	0.5		1.2		1.4
Other, net	—		(0.2	)	(0.3	)

Effective income tax rate	39.8	%	39.0	%	45.5	%

154

Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

The tax effect of temporary differences giving rise to significant portions of ComEd’s deferred tax assets and liabilities as of December 31, 2003 and 2002 are presented below:


	2003			2002
Deferred tax liabilities:
Plant basis difference	$	1,851		$	1,823
Deferred investment tax credits		48			51
Deferred debt refinancing costs		49			67

Total deferred tax liabilities		1,948			1,941

Deferred tax assets:
Deferred pension and postretirement obligations		(85	)		(104	)
Other, net		(151	)		(156	)

Total deferred tax assets		(236	)		(260	)

Deferred income tax liabilities (net) on the Consolidated Balance Sheets	$	1,712		$	1,681

In accordance with regulatory treatment of certain temporary differences, ComEd has recorded a net regulatory liability associated with deferred income taxes, pursuant to SFAS No. 71 and SFAS No. 109, “Accounting for Income Taxes,” of $61 million and $68 million at December 31, 2003 and 2002, respectively. See Note 16 – Supplemental Financial Information for more information of regulatory liabilities associated with deferred income taxes.

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, 2003 and 2002, a deferred tax liability of approximately $848 million and $860 million, respectively, 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 2004. 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.

In 2003 and 2002, ComEd received $86 million and $28 million, respectively, from Exelon related to ComEd’s allocation of tax benefits under Exelon’s Tax Sharing Agreement.

10. Nuclear Decommissioning

SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143) provides accounting requirements for retirement obligations (whether statutory, contractual or as a result of principles of promissory estoppel) associated with tangible long-lived assets. ComEd was required to adopt SFAS No. 143 as of January 1, 2003.

155

Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

Exelon was required to re-measure the decommissioning liabilities at fair value using the methodology prescribed by SFAS No. 143. The transition provisions of SFAS No. 143 required Exelon to apply this re-measurement back to the historical periods in which asset retirement obligations (ARO) were incurred, resulting in a re-measurement of these obligations at the date the related assets were acquired. Since the nuclear plants previously owned by ComEd were acquired by Exelon on October 20, 2000 (Merger Date) as a result of the Merger, Exelon’s historical accounting for its ARO has been revised as if SFAS No. 143 had been in effect at the Merger Date.

For the former ComEd plants, the calculation of the SFAS No. 143 ARO yielded decommissioning obligations lower than the value of the corresponding trust assets. ComEd has previously collected amounts from customers (which were subsequently transferred to Generation) in advance of Generation’s recognition of decommissioning expense under SFAS No. 143. While it is expected that the trust assets will ultimately be used entirely for the decommissioning of the plants, the current measurement required by SFAS No. 143 results in an excess of assets over related ARO liabilities. As such, in accordance with regulatory accounting practices and a December 2000 ICC Order, a regulatory liability of $948 million and a corresponding receivable from Generation were recorded at ComEd upon the adoption of SFAS No. 143. At December 31, 2003, this regulatory liability and corresponding receivable from Generation totaled $1,183 million. Exelon believes that all of the decommissioning assets, including up to $73 million of annual collections from ComEd ratepayers through 2006, will be used to decommission the former ComEd plants. Subsequent to 2006, there will be no further recoveries of decommissioning costs from ComEd’s customers. Additionally, any surplus funds after the nuclear stations are decommissioned must be refunded to customers. ComEd expects the regulatory liability and corresponding receivable from Generation will be reduced to zero at or before the conclusion of the decommissioning of the former ComEd plants.

As discussed above, Exelon re-measured its 2001 decommissioning-related balances associated with the Merger purchase price allocation at ComEd and the January 2001 corporate restructuring as if SFAS No. 143 had been in effect at the Merger Date. Exelon concluded that had SFAS No. 143 been in effect, ComEd would not have recorded an impairment of its regulatory asset for decommissioning of its retired nuclear plants as a purchase price allocation adjustment in 2001 as a result of the December 2000 ICC order. Increased net assets would have been transferred to Generation by ComEd in the corporate restructuring. Accordingly, ComEd recorded a reduction of $210 million of goodwill and of shareholders’ equity. In addition, ComEd recorded a cumulative effect of a change in accounting principle of $5 million to reverse goodwill amortization that had been recorded in 2001. ComEd also reclassified a regulatory asset related to nuclear decommissioning costs for retired units of $248 million to regulatory liabilities.

11. 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. Substantially all ComEd employees are eligible to participate in these plans. Benefits under these plans generally reflect each employee’s compensation, years of service, and age at retirement.

The pension obligation and non-pension postretirement benefits obligation on ComEd’s 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 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 and postretirement expense to the participating employers based upon several factors, including the percentage of active employees in each participating unit.

156

Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

See Note 14 – Retirement Benefits of the Notes to Exelon’s Consolidated Financial Statements for pension and other postretirement benefits information for the Exelon plans.

Approximately $51 million, $15 million and $17 million were included in operating and maintenance expense in 2003, 2002 and 2001, respectively, for ComEd’s allocated portion of Exelon’s pension and postretirement benefit expense. ComEd contributed $201 million and $89 million to the Exelon-sponsored plans in 2003 and 2002, respectively. ComEd expects to contribute up to $216 million to the pension benefit plans in 2004.

During 2003, ComEd recognized curtailment charges of $48 million associated with an overall reduction in participants in its pension and postretirement benefit plans due to employee reductions associated with The Exelon Way.

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, $19 million, and $20 million in 2003, 2002, and 2001, respectively.

12. Fair Value of Financial Assets and Liabilities

The carrying amounts and fair values of ComEd’s financial instruments as of December 31, 2003 and 2002 were as follows:


	2003				2002
	Carrying Amount		Fair Value		Carrying Amount			Fair Value
Non-derivatives:
Assets
Note receivable from affiliate (a)	$	1,071	$	1,077	$	1,284		$	1,226
Liabilities
Long-term debt (including amounts due within one year) (b)		4,403		4,735		5,966			6,671
Long-term debt to ComEd Transitional Trust (including amounts due within one year) (b)		1,676		1,791		—			—
Long-term debt to affiliates (including amounts due within one year) (b)		361		378		—			—
Mandatorily redeemable preferred securities (b)		—		—		330			459
Derivatives:
Fixed-to-floating interest-rate swaps	$	33	$	33	$	41		$	41
Forward interest-rate swaps		—		—		(52	)		(52	)

(a)	At December 31, 2003, ComEd had a $1,071 million note receivable from Unicom Investments Inc. as more fully described below.

(b)

Effective December 31, 2003, ComEd Financing II, ComEd Financing III and the ComEd Funding Trust were deconsolidated from the financial statements of ComEd in conjunction with the adoption of FIN No. 46-R. Amounts owed to ComEd Financing II, ComEd Financing III and ComEd Funding Trust were recorded as long-term debt to affiliate within the Consolidated Balance Sheets.

As of December 31, 2003 and 2002, 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 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 external dealer prices or internal valuation models which utilize assumptions of available market pricing curves.

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Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

Financial instruments that potentially subject ComEd to concentrations of credit risk consist principally of cash equivalents and customer and affiliate 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 No. 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 2003, ComEd paid $45 million net to counterparties to settle forward-starting interest-rate swaps, designated as cash-flow hedges, with an aggregate notional amount of $1,070 million. 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 related debt to interest expense. At December 31, 2003, ComEd had no forward-starting interest-rate swaps outstanding.

ComEd has also entered into interest-rate swaps to effectively convert $485 million in fixed-rate debt to floating-rate debt. These swaps have been designated as 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.

During 2003 and 2002, no amounts were reclassified from accumulated other comprehensive income into earnings as a result of forecasted financing transactions no longer being probable.

Note Receivable from Affiliate.

At December 31, 2003, ComEd had a $1,071 million note receivable from Unicom Investments Inc. (UII), an affiliate. The note, which matures on December 2011, bears interest at the one month forward LIBOR rate plus 50 basis points. During 2003, ComEd received a $213 million principal repayment from UII.

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Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

13. Preferred Securities

Preferred and Preference Stock.At December 31, 2003 and 2002, there were 6,810,451 authorized shares of preference stock and 850,000 authorized shares of prior preferred stock.


	December 31,
	Shares Outstanding		Dollar Amount
	2003	2002	2003		2002
Without mandatory redemption
Preference stock, non-cumulative, without par value	1,120	1,120	$	7	$	7

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

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

Mandatorily Redeemable Preferred Securities.Effective December 31, 2003, ComEd Financing II, ComEd Financing III, ComEd Funding and ComEd Funding Trust were deconsolidated from the financial statements in conjunction with the adoption of FIN No. 46-R. Amounts owed to these financing trusts are recorded as long-term debt to affiliates within the Consolidated Balance Sheets. Prior periods were not restated.

At December 31, 2002, subsidiary trusts of ComEd had outstanding the following securities:


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

Total						8,150,000	$	330

On March 20, 2003, ComEd Financing I, a financing subsidiary of ComEd, redeemed $200 million of 8.48% trust preferred securities at a redemption price of 100% of the principal amount, plus accrued distributions. ComEd redeemed $206 million of its 8.48% subordinated debentures issued to ComEd Financing I. The preferred securities were refinanced with the proceeds from a March 17, 2003 issue of $200 million of 6.35% trust preferred securities by ComEd Financing III, a financing subsidiary of ComEd, which are mandatorily redeemable in 2033. The 8.48% subordinated debentures were refinanced with the proceeds from a March 17, 2003 issue of $206 million of 6.35% subordinated debentures due 2033 from ComEd to ComEd Financing III.

ComEd Financing II and ComEd Financing III are 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.

Prior to the adoption of FIN No. 46-R, the interest expense on the deferrable interest debt securities was included in Distributions on Mandatorily Redeemable Preferred Securities in ComEd’s Consolidated Statements of Income and is deductible for income tax purposes. Beginning January 1, 2004, ComEd will begin recording interest expense associated with this debt in interest expense to affiliates.

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Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

The preferred securities issued by each of ComEd Financing II and ComEd Financing III 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.

14. Common Stock

At December 31, 2003 and 2002, common stock with a $12.50 par value consisted of 250,000,000 and 250,000,000 shares authorized and 127,016,484 and 127,016,409 shares outstanding, respectively.

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

At December 31, 2003 and 2002, 76,068 and 76,305 warrants, respectively, were outstanding to purchase ComEd common stock. 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, 2003, 25,356 shares of common stock were reserved for the conversion of warrants.

Stock Repurchases.

As part of the corporate restructuring on January 1, 2001, 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:


(in thousands)	Common Shares		Treasury Shares		Total
Balance, December 31, 2001	163,805		36,789		127,016
Retirement of treasury shares	(36,789	)	(36,789	)	—

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

Balance, December 31, 2003	127,016		—		127,016

Fund Transfer Restrictions.

Under applicable federal law, ComEd can pay dividends only from retained or current earnings. Under Illinois law, ComEd may not pay any dividend on its stock unless “[its] earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEd has also agreed in connection with financings arranged through ComEd Financing II and ComEd Financing III (the Financing Trusts) that it will 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 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. At December 31, 2003, ComEd had retained earnings of $883 million, of which $709 million had been appropriated for future dividend payments.

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Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

15. Commitments and Contingencies

Energy Commitments.

In connection with the 2001 corporate restructuring, ComEd assigned its respective rights and obligations under various purchased power and fuel supply agreements to Generation. Additionally, ComEd entered into a purchase 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. An extension of this contract for 2005 and 2006 has been agreed to by ComEd and Generation with substantially the same terms as the PPA currently in effect, except for the prices for energy which were reset to reflect the current rates at the time the extension was agreed to. This extension must still be filed with the ICC. Subsequent to 2006, ComEd will obtain all of its supply from market sources, which could include Generation.

Commercial Commitments.

ComEd’s commercial commitments as of December 31, 2003 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:


	Total		Expiration within
(in millions)	Total		2004		2005-2006		2007-2008		2009 and beyond
Letters of credit (non-debt) (a)	$	25	$	25	$	—	$	—	$	—
Midwest Generation Capacity Reservation Agreement guarantee (b)		32		3		7		8		14
Surety bonds (c)		3		3		—		—		—

Total commercial commitments	$	60	$	31	$	7	$	8	$	14

(a)	Letters of credit (non-debt) – ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.

(b)

Midwest Generation Capacity Reservation Agreement guarantee – In connection with ComEd’s agreement with the City of Chicago (Chicago) entered into on February 20, 2003, Midwest Generation assumed from Chicago a Capacity Reservation Agreement that Chicago had entered into with Calumet Energy Team, LLC. ComEd will reimburse Chicago for any nonperformance by Midwest Generation under the Capacity Reservation Agreement. Under FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others” (FIN No. 45), $3 million is included as a liability on ComEd’s Consolidated Balance Sheets. Additional information regarding this liability is included within this section under the heading “Credit Contingencies” below.

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

Environmental Issues.

ComEd’s operations have in the past and may in the future require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, ComEd is generally liable for the costs of remediating environmental contamination of property now or formerly owned by ComEd and of property contaminated by hazardous substances generated by ComEd. ComEd owns or leases a number of real estate parcels, including parcels on which its operations or the operations of others may have resulted in

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Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

contamination by substances which are considered hazardous under environmental laws. ComEd has identified 42 sites where former manufactured gas plant (MGP) activities have or may have resulted in actual site contamination. Of these 42 sites, the Illinois Environmental Protection Agency has approved the clean-up of three sites. 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, 2003 and 2002, ComEd had accrued $69 million and $101 million, respectively, for environmental investigation and remediation costs, including $64 million and $97 million, respectively (reflecting a discount rate of 5.0%) for investigation and remediation at its 39 MGP sites, that currently can be reasonably estimated. Such estimates, reflecting the effects of a 2.5% inflation rate before the effects of discounting were $94 million and $138 million at December 31, 2003 and 2002, respectively. 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.

As of December 31, 2003, ComEd anticipates that payments related to the discounted environmental investigation and remediation costs, recorded on an undiscounted basis were:


2004	$	10
2005		12
2006		8
2007		8
2008		5
Remaining years		51

Total payments	$	94

Leases.

Minimum future operating lease payments, including lease payments for real estate and vehicles, as of December 31, 2003 were:


2004	$	14
2005		12
2006		12
2007		12
2008		11
Remaining years		55

Total minimum future lease payments	$	116

Rental expense under operating leases totaled $17 million, $26 million, and $23 million in 2003, 2002, and 2001, respectively.

Litigation.

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

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Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

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 and for breach of contract. On November 25, 2002, the court granted the developers’ motions for summary judgment. The judge also entered a permanent injunction enjoining ComEd from refusing to pay the retail rate on the grounds of the amendment and Illinois from denying ComEd a tax credit on account of such purchases. 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. While ComEd cannot currently predict the outcome of this action, ComEd does not believe that it will have a material adverse impact on ComEd’s results of operations.

General. ComEd is involved in various other litigation matters that are being defended and handled in the ordinary course of business, and ComEd maintains accruals for such costs that are probable of being incurred and subject to reasonable estimation. 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 its financial condition or results of operations.

Capital Commitments.

ComEd estimates that it will spend approximately $616 million for capital expenditures in 2004.

Credit Contingencies.

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 ($6 million was paid during the first quarter of 2003) 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 Midwest Agreement, ComEd received from Midwest Generation $22 million during the first quarter 2003 and $10 million during April 2003, to relieve Midwest Generation’s obligation under the fossil sale agreement. Midwest Generation also assumed from Chicago a Capacity Reservation Agreement that Chicago had entered into with Calumet Energy Team, LLC (CET), which is effective through June 2012. ComEd is obligated to reimburse Chicago for any nonperformance by Midwest Generation under the Capacity Reservation Agreement and paid approximately $2 million for amounts owed to CET by Chicago at the time the agreement was executed. In the first quarter of 2003, ComEd recorded a guarantee liability of $4 million under the provisions of FIN No. 45 related to its obligation to reimburse Chicago for any nonperformance by Midwest Generation. The net effect of the settlement to ComEd will be amortized on a straight-line basis over the remaining life of the franchise agreement with Chicago.

Income Tax Refund Claims.

ComEd has entered into several agreements with a tax consultant related to the filing of refund claims with the Internal Revenue Service (IRS) and has made refundable prepayments of $11 million during 2003 for potential fees associated with these agreements. The fees for these agreements are contingent upon a successful outcome and are based upon a percentage of the refunds recovered from the IRS, if any. As such, ComEd would have positive net cash flows related to these agreements if any fees are paid to the tax consultant. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of ComEd. ComEd’s tax benefits for periods prior to the Merger would be recorded as a reduction of goodwill pursuant to a reallocation of the Merger purchase price. ComEd cannot predict the timing of the final resolution of these refund claims.

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Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

16. Supplemental Financial Information

Supplemental Income Statement Information


	For the Year Ended December 31,
	2003		2002		2001
Depreciation and amortization:
Property, plant and equipment (a)	$	342	$	358	$	369
Regulatory assets		44		164		170
Goodwill		—		—		126

Total depreciation and amortization	$	386	$	522	$	665

(a)	Includes amortization of capitalized software costs.


	For the Year Ended December 31,
	2003			2002		2001
Taxes other than income
Utility (a)	$	233		$	232	$	238
Real estate		29			20		33
Payroll		24			28		28
Other (b)		(19	)		7		(3	)

Total	$	267		$	287	$	296

(a)	Represents municipal and state utility taxes which are also recorded in revenues on ComEd’s Consolidated Statements of Income.

(b)	In 2003, ComEd received a $25 million credit for use tax payments for periods prior to the Merger.


	For the Year Ended December 31,
	2003			2002			2001
Other, net
Investment income	$	4		$	11		$	18
Gain on disposition of assets, net		4			—			—
AFUDC		9	(a)		18			17
Reserve for potential plant disallowance		12			(12	)		—
Other income (expense)		(5	)		(4	)		—

Total	$	24		$	13		$	35

(a)	In 2003, the debt portion of AFUDC of $6 million was recorded as a non-cash credit to interest expense.

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Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

Supplemental Cash Flow Information


	For the Year Ended December 31,
	2003		2002		2001
Cash paid during the year:
Interest (net of amount capitalized)	$	352	$	417	$	451
Income taxes (net of refunds)		579		264		300
Non-cash investing and financing:
Net assets transferred as a result of the corporate restructuring, net of note payable	$	—	$	—	$	1,368
Contribution of receivable from parent		—		—		1,062
Resolution of certain tax matters and merger severance adjustments		8		14		—
Purchase accounting estimate adjustments		—		—		(85	)
Regulatory asset fair value adjustments		—		—		347
Retirement of treasury shares		—		1,344		2,023
Adoption of SFAS No. 143 – adjustment to other paid in capital and goodwill		210		—		—

Supplemental Balance Sheet Information


	December 31,
	2003			2002
Regulatory assets (liabilities)
Nuclear decommissioning (See Note 10 – Nuclear Decommissioning)	$	(1,183	)	$	—
Removal costs		(973	)		(933	)
Nuclear decommissioning costs for retired plants		—			248
Recoverable transition costs		131			175
Reacquired debt costs and interest-rate swap settlements		172			84
Deferred income taxes (see Note 9 - Income Taxes)		(61	)		(68	)
Other		23			8

Total	$	(1,891	)	$	(486	)

Nuclear decommissioning costs– Generation is responsible for decommissioning the nuclear plants formerly owned by ComEd. These costs represent the amount of estimated present value of future nuclear decommissioning costs that are less than the associated decommissioning trust fund assets. Generation believes the trust fund assets, including any future collections from ratepayers, will equal the associated future decommissioning costs at the time of decommissioning.

Removal costs -These amounts represent funds received from ratepayers to cover the future removal of property, plant and equipment. See Note 4 – Property, Plant and Equipment for further information.

Recoverable transition costs - These charges, related to the recovery of ComEd’s former generating plants, are amortized based on the expected return on equity of ComEd in any given year. ComEd expects to fully recover and amortize these charges by the end of 2006, but may increase or decrease its annual amortization to maintain its earnings within the earnings cap provisions established by Illinois legislation. See Note 2 – Regulatory Issues for discussion of recoverable transition cost amortization.

Reacquired debt costs and interest-rate swap - The reacquired debt costs represent premiums paid for the early extinguishment and refinancing of long-term debt, which are amortized over the life of the new debt issued to finance the debt redemption. Interest-rate swap settlements are deferred and amortized over the period that the related debt is outstanding.

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Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

Deferred income taxes - These costs represent the difference between the method in which the regulator allows for the recovery of income taxes and how income taxes would be recorded by unregulated entities. These regulatory assets and liabilities associated with deferred income taxes, recorded in compliance with SFAS No. 71 and SFAS No. 109, “Accounting for Income Taxes,” include the deferred tax effects associated principally with excess deferred taxes accounted for in accordance with the ratemaking policies of the ICC, as well as the revenue impacts thereon, and assume continued recovery or settlement of these costs in future rates.

Recovery/Settlement of Regulatory Assets and Liabilities -The regulatory assets for reacquired debt costs and interest-rate swap settlements relate to ComEd’s transmission and distribution business which is subject to cost-based rate regulation. Therefore, they are earning a rate of return. The regulatory assets for recoverable transition costs represent generation-related costs which are recoverable through regulated cash flows. 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 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,
	2003		2002
Accrued expenses
Accrued expenses	$	148	$	121
Taxes accrued		179		234
Interest accrued		213		183

Total	$	540	$	538

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Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

17. Related-Party Transactions

ComEd’s financial statements include related-party transactions with its unconsolidated subsidiaries as reflected in the table below.


	December 31,
	2003 (1)		2002
Receivables from affiliates (current)
ComEd Funding Trust	$	9	$	—
Investment in subsidiaries
ComEd Funding		45		—
ComEd Financing II		8		—
ComEd Financing III		6		—
Receivable from affiliates (noncurrent)
ComEd Funding Trust		9		—
Payables to affiliates (current)
ComEd Financing II		6		—
ComEd Financing III		4		—
Long-term debt to affiliates (including due within one year)
ComEd Funding Trust		1,676		—
ComEd Financing II		155		—
ComEd Financing III		206		—

(1)

Effective December 31, 2003, ComEd Financing II, ComEd Financing III, ComEd Funding and the ComEd Funding Trust were deconsolidated from the financial statements of ComEd in conjunction with the adoption of FIN No. 46-R. Amounts owed to ComEd Financing II, ComEd Financing III and ComEd Funding Trust were recorded as long-term debt to affiliate within the Consolidated Balance Sheets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

In addition to the transactions described above, ComEd’s financial statements include related-party transactions as reflected in the tables below.


	For the Year Ended December 31,
	2003			2002		2001
Operating revenues from affiliates
Generation (1)	$	50		$	51	$	39
Enterprises (1)		15			12		42
Purchased power from affiliate
PPA with Generation (2)		2,479			2,559		2,656
Operations & maintenance from affiliates
BSC (3)		115			124		114
Enterprises (4, 5)		26			12		21
PECO (11)		(5	)		—		—
Interest income from affiliates
UII (6)		21			30		61
PECO (7)		—			—		8
Generation (8)		—			—		9
Exelon intercompany money pool (13)		2			—		—
Other		2			1		1
Interest expense from affiliate
Generation (2, 9)		—			4		10
Capitalized costs
BSC (3)		4			9		23
Enterprises (5)		21			21		26
Cash dividends paid to parent		401			470		483


	December 31,
	2003		2002
Receivables from affiliates (current)
UII (6)	$	3	$	15
PECO (11)		6		—
Exelon intercompany money pool (13)		405		—
Other		5		—
Receivables from affiliates (noncurrent)
UII (6)		1,071		1,284
Generation (14)		1,183		—
Other		8		16
Payables to affiliates (current)
Generation decommissioning (10)		11		59
Generation (1, 2, 8)		171		339
BSC (3, 8)		13		18
Other		2		—
Payables to affiliates (noncurrent)
Generation decommissioning (10)		22		218
Other		6		6
Shareholders’ equity – receivable from parent (12)		250		615

(1)	ComEd provides electric, transmission, and other ancillary services to Generation and Enterprises.

(2)	Effective January 1, 2001, ComEd entered into a PPA with Generation. See Note 15 - Commitments and Contingencies for further information regarding the PPA. The payable to Generation primarily consists of

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Commonwealth Edison Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Dollars in millions, unless otherwise noted)

services related to the PPA. During 2002, ComEd accrued interest expense on deferred PPA payments of $4 million.

(3)	ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial and information technology services. A portion of such services, provided at cost including applicable overhead, is capitalized.

(4)	ComEd has contracted with Exelon Services (an Enterprises company) to provide energy conservation services to ComEd customers.

(5)	ComEd receives substation and transmission engineering and construction services under contracts with InfraSource. A portion of such services is capitalized. Exelon sold InfraSource in September 2003.

(6)	ComEd has a note and interest receivable with a variable rate of the one month forward LIBOR rate plus 50 basis points from Unicom Investments Inc. (UII) relating to the December 1999 fossil plant sale. This note matures in December 2011.

(7)	At December 31, 2000, ComEd had a $400 million receivable from PECO, which was repaid in the second quarter of 2001.

(8)	ComEd processes certain invoice payments on behalf of Generation and BSC. During 2001, ComEd earned interest from Generation relating to these invoice payments.

(9)	In consideration for the net assets transferred as part of the corporate restructuring effective January 1, 2001, ComEd had a note payable to affiliates of $463 million. This note payable was repaid during 2001.

(10)	ComEd has a short-term and long-term payable to Generation, primarily representing ComEd’s legal requirements to remit collections of nuclear decommissioning costs from customers to Generation.

(11)	In 2003, ComEd provided hurricane restoration assistance to PECO.

(12)	ComEd has a non-interest bearing receivable from Exelon related to a corporate restructuring in 2001. The receivable is expected to be settled over the years 2004 through 2008.

(13)	ComEd participates in Exelon’s intercompany money pool. ComEd earns interest on its investment in the money pool at a market rate of interest.

(14)	ComEd has a receivable from Generation related to a regulatory liability as a result of the adoption of SFAS No. 143. For further information see Note 10 – Nuclear Decommissioning.

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				Income Before Cumulative Effect of a Change in Accounting Principle				Net Income
	2003		2002		2003		2002		2003		2002		2003		2002
Quarter ended:
March 31	$	1,424	$	1,315	$	411	$	332	$	190	$	129	$	195	$	129
June 30		1,361		1,481		443		502		205		231		205		231
September 30		1,737		1,938		363		490		163		215		163		215
December 31		1,292		1,390		350		442		144		215		144		215

19. Subsequent Events

On January 15, 2004, ComEd redeemed at maturity $26 million of its 5.3% pollution control bonds collateralized by first mortgage bonds. The proceeds from an issuance of $20 million of pollution control bonds in December 2003 and available cash were used to redeem these bonds.

On January 15, 2004, ComEd redeemed at maturity $150 million of its 7.375% notes.

169

PECO

Report of Independent Auditors

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, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 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 1 to the consolidated financial statements, PECO changed its method of accounting for derivative instruments and hedging activities as of January 1, 2001 and its method of accounting for variable interest entities in 2003; and as discussed in Note 9 to the consolidated financial statements, PECO changed its method of accounting for asset retirement obligations as of January 1, 2003.

PricewaterhouseCoopers LLP

Chicago, Illinois

January 28, 2004

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Consolidated Statements of Income


	For the Years Ended December 31,
(in millions)	2003			2002			2001
Operating revenues
Operating revenues	$	4,377		$	4,321		$	3,953
Operating revenues from affiliates		11			12			12

Total operating revenues		4,388			4,333			3,965

Operating expenses
Purchased power		244			231			190
Purchased power from affiliates		1,433			1,438			1,162
Fuel		419			348			450
Operating and maintenance		519			450			494
Operating and maintenance from affiliates		57			73			93
Depreciation and amortization		487			456			416
Taxes other than income		173			244			161

Total operating expenses		3,332			3,240			2,966

Operating income		1,056			1,093			999

Other income and deductions
Interest expense		(321	)		(370	)		(405	)
Interest expense to affiliates		(3	)		—			(8	)
Distributions on mandatorily redeemable preferred securities		(8	)		(10	)		(10	)
Interest income from affiliates		—			—			10
Equity in earnings of unconsolidated affiliates		—			1			—
Other, net		2			31			36

Total other income and deductions		(330	)		(348	)		(377	)

Income before income taxes		726			745			622
Income taxes		253			259			197

Net income		473			486			425
Preferred stock dividends		5			8			10

Net income on common stock	$	468		$	478		$	415

See Notes to Consolidated Financial Statements

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PECO Energy Company and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(in millions)	2003			2002			2001
Cash flows from operating activities
Net income	$	473		$	486		$	425
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization		487			456			416
Provision for uncollectible accounts		52			46			69
Deferred income taxes and amortization of investment tax credits		(50	)		(92	)		(66	)
Equity in earnings of unconsolidated affiliates		—			(1	)		—
Other operating activities		8			8			91
Changes in assets and liabilities:
Accounts receivable		(24	)		(145	)		(54	)
Inventories		(32	)		4			(15	)
Other current assets		(2	)		(6	)		5
Accounts payable, accrued expenses and other current liabilities		(38	)		22			(133	)
Deferred energy costs		(50	)		25			29
Change in receivables and payables to affiliates, net		(31	)		(41	)		73
Pension and non-pension postretirement benefits obligations		9			(9	)		(24	)
Other noncurrent assets and liabilities		12			7			18

Net cash flows provided by operating activities		814			760			834

Cash flows from investing activities
Capital expenditures		(250	)		(261	)		(248	)
Change in restricted cash		—			(8	)		(69	)
Other investing activities		4			9			7

Net cash flows used in investing activities		(246	)		(260	)		(310	)

Cash flows from financing activities
Issuance of long-term debt		450			225			1,055
Retirement of long-term debt		(718	)		(571	)		(1,416	)
Issuance of long-term debt to affiliates		103			—			—
Change in short-term debt		(154	)		99			(60	)
Retirement of mandatorily redeemable preferred stock		(50	)		(19	)		(18	)
Retirement of preferred stock		(50	)		—			—
Dividends paid on preferred and common stock		(327	)		(348	)		(352	)
Contribution from parent		159			150			225
Change in receivable and payable to affiliates, net		—			—			25
Other financing activities		—			(5	)		31

Net cash flows used in financing activities		(587	)		(469	)		(510	)

Increase (decrease) in cash and cash equivalents		(19	)		31			14
Cash transferred in restructuring		—			—			(31	)
Cash and cash equivalents at beginning of period		63			32			49

Cash and cash equivalents at end of period	$	44		$	63		$	32

See Notes to Consolidated Financial Statements

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PECO Energy Company and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(in millions)	2003			2002
Assets
Current assets
Cash and cash equivalents	$	44		$	63
Restricted cash		—			331
Accounts receivable, net
Customer		363			379
Other		27			39
Inventories, at average cost
Gas		99			67
Materials and supplies		7			8
Deferred energy costs		81			31
Other		11			9

Total current assets		632			927

Property, plant and equipment, net		4,256			4,159

Deferred debits and other assets
Regulatory assets		5,226			5,546
Investments		39			19
Receivable from affiliates		117			—
Prepaid pension asset		68			41
Other		8			28

Total deferred debits and other assets		5,458			5,634

Total assets	$	10,346		$	10,720

Liabilities and shareholders’ equity
Current liabilities
Commercial paper	$	46		$	200
Payables to affiliates		150			170
Long-term debt due within one year		—			689
Long-term debt to PECO Energy Transitional Trust due within one year		153			—
Accounts payable		92			87
Accrued expenses		237			332
Deferred income taxes		29			27
Other		35			33

Total current liabilities		742			1,538

Long-term debt		1,359			4,951
Long-term debt to affiliates		184			—
Long-term debt to PECO Energy Transitional Trust		3,696			—

Deferred credits and other liabilities
Deferred income taxes		2,893			2,903
Unamortized investment tax credits		22			24
Non-pension postretirement benefits obligation		287			251
Other		147			164

Total deferred credits and other liabilities		3,349			3,342

Total liabilities		9,330			9,831

Commitments and contingencies
Mandatorily redeemable preferred securities		—			128

Shareholders’ equity
Common stock		1,999			1,976
Receivable from parent		(1,623	)		(1,758	)
Preferred stock		87			137
Retained earnings		546			401
Accumulated other comprehensive income		7			5

Total shareholders’ equity		1,016			761

Total liabilities and shareholders’ equity	$	10,346		$	10,720

See Notes to Consolidated Financial Statements

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PECO Energy Company and Subsidiary Companies

Consolidated Statements of Changes in Shareholders’ Equity


(in millions)	Common Stock			Preferred Stock			Receivable from Parent			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity
Balance, December 31, 2000	$	1,449		$	137		$	—		$	190		$	(1	)	$	1,775
Net income		—			—			—			425			—			425
Common stock dividends		—			—			—			(342	)		—			(342	)
Preferred stock dividends		—			—			—			(10	)		—			(10	)
Receivable from parent		1,983			—			(1,983	)		—			—			—
Repayment of receivable from parent		—			—			105			—			—			105
Stock option exercises		(26	)		—			—			—			—			(26	)
Capital contribution from parent		121			—			—			—			—			121
Net assets transferred in restructuring		(1,608	)		—			—			—			—			(1,608	)
Other comprehensive income, net of income taxes of $16		—			—			—			—			20			20

Balance, December 31, 2001		1,919			137			(1,878	)		263			19			460
Net income		—			—			—			486			—			486
Common stock dividends		—			—			—			(340	)		—			(340	)
Preferred stock dividends		—			—			—			(8	)		—			(8	)
Repayment of receivable from parent		—			—			120			—			—			120
Capital contribution from parent		30			—			—			—			—			30
Allocation of tax benefit from parent		27			—			—			—			—			27
Other comprehensive income, net of income taxes of $(9)		—			—			—			—			(14	)		(14	)

Balance, December 31, 2002		1,976			137			(1,758	)		401			5			761
Net income		—			—			—			473			—			473
Common stock dividends		—			—			—			(322	)		—			(322	)
Preferred stock dividends		—			—			—			(5	)		—			(5	)
Redemption of preferred stock		—			(50	)		—			(1	)		—			(51	)
Repayment of receivable from parent		—			—			135			—			—			135
Capital contribution from parent		17			—			—			—			—			17
Allocation of tax benefit from parent		7			—			—			—			—			7
Return of equity from unconsolidated affiliate		(1	)		—			—			—			—			(1	)
Other comprehensive income, net of income taxes of $1		—			—			—			—			2			2

Balance, December 31, 2003	$	1,999		$	87		$	(1,623	)	$	546		$	7		$	1,016

See Notes to Consolidated Financial Statements

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PECO Energy Company and Subsidiary Companies

Consolidated Statements of Comprehensive Income


	For the Years Ended December 31,
(in millions)	2003		2002			2001
Net income	$	473	$	486		$	425
Other comprehensive income (loss)
SFAS No. 133 transition adjustment, net of income taxes of $29	$	—	$	—		$	40
Cash-flow hedge fair value adjustment, net of income taxes of $(8) and $(13), respectively		—		(13	)		(20	)
Unrealized gain (loss) on marketable securities, net of income taxes of $1 and $(1), respectively		2		(1	)		—

Total other comprehensive income (loss)		2		(14	)		20

Total comprehensive income	$	475	$	472		$	445

See Notes to Consolidated Financial Statements

175

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 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 requires the unbundling of retail electric services in Pennsylvania into separate generation, transmission and distribution services with open retail competition for generation services. 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.

Basis of Presentation

On October 20, 2000, Exelon Corporation (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, and Exelon. As a result of the Merger, PECO is a principal subsidiary of Exelon, which owns 100% of PECO’s common stock. During January 2001, Exelon undertook a corporate restructuring to separate its generation and other competitive businesses from its regulated energy delivery businesses at PECO and ComEd. As part of the restructuring, the generation-related operations and assets and liabilities of PECO were transferred to Exelon Generation Company, LLC (Generation). Additionally, certain operations and assets and liabilities of PECO were transferred to Exelon Business Services Company (BSC).

The consolidated financial statements of PECO at December 31, 2003 include the accounts of its ExTel Corporation, LLC, Adwin Realty Company and PECO Wireless, LP. All intercompany transactions have been eliminated. As of July 1, 2003, PECO Trust IV was no longer consolidated within the financial statements of PECO. Effective December 31, 2003, the accounts of PECO Energy Transition Trust and PECO Energy Capital Corporation are no longer consolidated. See “Variable Interest Entities” below. PECO accounts for its less than 20% owned investments under the cost method of accounting.

Reclassifications

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

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States (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 revenues, derivatives, environmental costs, allowance for doubtful accounts, fixed asset depreciation, taxes and pension and other postretirement benefits.

Accounting for the Effects of Regulation

PECO is regulated by the Pennsylvania Public Utility Commission (PUC) under state public utility laws, the Federal Energy Regulatory Commission (FERC) under various Federal laws, and the Securities and Exchange

176

PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA). PECO accounts for all of its regulated electric and gas 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,” (SFAS No. 71) which requires PECO to record in its 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 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 and liabilities associated with these operations will be recovered or settled. 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.

Segment Information

PECO operates in one segment – energy delivery. Energy delivery consists of the retail electric distribution and transmission business of PECO in southeastern Pennsylvania, and the sale of natural gas and distribution services by PECO in four Pennsylvania counties surrounding the city of Philadelphia

Variable Interest Entities

The FASB issued FASB Interpretation (FIN) No. 46 “Consolidation of Variable Interest Entities” (FIN No. 46) in January 2003 and issued its revision in FASB Interpretation No. 46-R “Consolidation of Variable Interest Entities” (FIN No. 46-R) in December 2003, which addressed the requirements for consolidating certain variable interest entities. FIN No. 46 was effective for PECO’s variable interest entities created after January 31, 2003 and FIN No. 46-R was effective December 31, 2003 for PECO’s other variable interest entities that are considered to be special-purpose entities. FIN No. 46-R applies to all other variable interest entities as of March 31, 2004.

PECO Energy Capital Trust IV (PECO Trust IV), a financing subsidiary of PECO created in May 2003, was not consolidated within the financial statements of PECO pursuant to the provisions of FIN No. 46 as of July 1, 2003. As of December 31, 2003, the remaining financing trusts of PECO, including PECO Energy Capital Trust III (PECO Trust III) and PECO Energy Transition Trust (PETT), were not consolidated within the financial statements of PECO pursuant to the provisions of FIN No. 46-R. Amounts of $4.0 billion owed to these financing trusts were recorded as debt to affiliates and debt to PECO Transitional Trust within the Consolidated Balance Sheets at December 31, 2003. PECO recognized equity in earnings related to these unconsolidated financing subsidiaries of less than $1 million for the year ended December 31, 2003. This change in presentation had no impact on PECO’s net income. In accordance with FIN No. 46-R, prior periods have not been restated.

Instruments with Characteristics of Both Liabilities and Equity

Most of the guidance of SFAS No. 150 was effective for all financial instruments entered into or modified after May 31, 2003, and otherwise was effective for PECO as of July 1, 2003. As a result of the implementation

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PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

of FIN No. 46-R and the subsequent deconsolidated of certain financing subsidiaries of PECO, the implementation of SFAS No. 150 had no impact for the year ended December 31, 2003 on PECO’s financial position or results of operations.

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 3 - Accounts Receivable for further discussion.

Stock-Based Compensation

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). PECO adopted the additional disclosure requirements of SFAS No. 148 in 2002 and continues to account for its stock-compensation plans under the disclosure-only provision 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, 2003, 2002 and 2001:


	2003		2002		2001
Net income – as reported	$	473	$	486	$	425
Deduct: total stock-based compensation expense determined under fair-value method for all awards, net of income taxes		3		13		15

Pro forma net income	$	470	$	473	$	410

Income Taxes

Deferred Federal and state income taxes are provided on all significant temporary differences between the book basis and the tax basis of assets and liabilities and for 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 Exelon consolidated group are allocated to PECO based on the separate return method (see Note 8 - Income Taxes.).

PECO is a party to an agreement (the “Tax Sharing Agreement”) that provides for the allocation of consolidated tax liabilities. The Tax Sharing Agreement generally provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to other members. That allocation is treated as a contribution to the capital of the party receiving the benefit.

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 life of the new debt issued to finance the debt redemption consistent with rate recovery for ratemaking purposes.

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.

178

PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

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

Prior to the adoption of FIN No. 46-R, the restricted cash of PETT was included in PECO’s Consolidated Balance Sheets. As of December 31, 2002, the restricted cash reflected escrowed cash to be applied to the principal and interest payments on the debt issued by PETT.

Inventories

Gas inventory includes the cost of stored natural gas and propane. PECO has several long-term storage contracts as well as a liquefied natural gas facility. Gas inventory is recorded using a weighted average cost.

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. At December 31, 2003 and 2002, PECO had no held-to-maturity or trading securities.

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 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, which are subject to periodic review by the PUC. At December 31, 2003 and 2002, deferred energy costs of $81 million and $31 million, respectively, which are expected to be recovered under the fuel adjustment clause, were recorded in other current assets on PECO’s Consolidated Balance Sheets

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 for impairment whenever circumstances indicate the carrying value of those assets may not be recoverable under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.”

Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation and removal costs reduce the related regulated liability 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 any gain or loss on disposition. (See Note 4 – Property, Plant and Equipment.)

Capitalized Software Costs

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PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, not to exceed ten years. During 2003, 2002, and 2001, PECO amortized capitalized software costs of $15 million, $17 million, and $16 million, respectively.

Depreciation and Amortization

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


Asset Category	2003		2002		2001
Electric-transmission and distribution	2.08	%	2.09	%	2.13	%
Gas	2.38	%	2.13	%	2.34	%
Common – gas and electric	7.53	%	6.40	%	6.26	%
Other property and equipment	1.27	%	0.71	%	0.60	%

Amortization of regulatory assets is provided over the recovery period as specified in the related regulatory agreement.

Allowance for Funds Used During Construction

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, $1 million and $2 million in 2003, 2002 and 2001, 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.

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, in which case those changes are recorded in other comprehensive income.

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.

180

PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

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. In connection with Exelon’s Risk Management Policy, PECO enters into derivatives to manage its exposure to fluctuation 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.

New Accounting Pronouncements

Through Exelon’s postretirement benefit plans, PECO provides retirees with prescription drug coverage. On December 8, 2003 the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Prescription Drug Act) was enacted. The Prescription Drug Act introduced a prescription drug benefit under Medicare as well as a Federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. In response to the enactment of the Prescription Drug Act, the FASB issued FASB Staff Position (FSP) FAS 106-1 (FSP FAS 106-1) in January 2004, which permits a plan sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer the accounting for the effects of the Prescription Drug Act. Exelon has made the one-time election allowed by FSP FAS 106-1. Thus, PECO’s financial statements and Note 10 – Retirement Benefits do not reflect the effects of the Prescription Drug Act on PECO’s allocated portion of Exelon’s postretirement plans. Exelon is evaluating what impact the Prescription Drug Act will have on its postretirement benefit plans and whether it will be eligible for a Federal subsidy beginning in 2006. Specific authoritative guidance on the accounting for the Federal subsidy is pending, and that guidance, when issued, could require PECO to change previously reported information.

As discussed above, FIN No. 46 was effective for PECO’s variable interest entities created after January 31, 2003 and FIN No. 46-R was effective December 31, 2003 for PECO’s other variable interest entities that are considered to be special-purpose entities. FIN No. 46-R applies to all other variable interest entities as of March 31, 2004. PECO continues to review other entities with which PECO and its subsidiaries have business arrangements to determine if those entities are variable interest entities under FIN No. 46-R and, if so, whether consolidation of these entities will be required as of March 31, 2004.

2. Regulatory Issues

In 2003, the phased process to implement competition in the electric industry continued as mandated by the requirements of the PUC’s Final Restructuring Order as further discussed below.

Nuclear Decommissioning Cost Adjustment Clause.On July 25, 2003, the PUC approved an adjustment to PECO’s Nuclear Decommissioning Cost Adjustment clause. Effective January 1, 2004, PECO will be permitted to recover an additional $3.6 million annually, or $33 million compared to $29 million previously, all of which is remitted to Generation.

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PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

Customer Choice.The 1998 Electric Restructuring Settlement approved by the PUC established a market share threshold (MST) to promote competition. The MST requirements provided that if, as of January 1, 2003, less than 50% of residential and commercial customers had chosen an alternative electric generation supplier, the number of customers sufficient to meet the MST would be randomly selected and assigned to an alternative electric generation supplier through a PUC-determined process. On January 1, 2003, the number of customers choosing an alternative electric generation supplier did not meet the MST. As a result of a PUC-approved auction process, approximately 64,000 small commercial and industrial customers and 267,000 residential customers were selected to participate in the MST program of which approximately 50,000 and 194,000 enrolled with alternative electric generation suppliers in May 2003 and December 2003, respectively. Any customer transferred has the right to return to PECO at any time. PECO does not expect the transfer of customers pursuant to the MST plan to have a material impact on its results of operations, financial position or cash flows.

3. Accounts Receivable

Customer accounts receivable at December 31, 2003 and 2002 included unbilled operating revenues of $143 million and $129 million, respectively. The allowance for uncollectible accounts at December 31, 2003 and 2002 was $72 million.

PECO has made changes to its accounting estimate processes related to the allowance for uncollectible accounts. As a result, the allowance for uncollectible accounts reserve was reduced by $17 million in the fourth quarter of 2002.

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, 2003, PECO had sold a $225 million interest in accounts receivable, consisting of a $176 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,” (SFAS No. 140) and a $49 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable. 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 and a $61 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable (see Note 7 - 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, 2003 and 2002, PECO met this requirement and was not required to make any cash deposits.

182

PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

4. Property, Plant and Equipment

A summary of property, plant and equipment by classification as of December 31, 2003 and 2002 is as follows:


Asset Category	2003		2002
Electric – transmission and distribution	$	4,458	$	4,269
Gas – transmission and distribution		1,387		1,319
Common		376		370
Construction work in progress		64		127
Other property, plant and equipment		19		19

Total property, plant and equipment		6,304		6,104
Less accumulated depreciation		2,048		1,945

Property, plant and equipment, net	$	4,256	$	4,159

Depreciation expense, which is included in cost of service for rate purposes, includes an estimated cost of dismantling and removing plant from service upon retirement. In accordance with regulatory accounting practice, collections for future removal costs are recorded as a regulatory liability. See Note 15 – Supplemental Information for more information on PECO’s regulatory liability related to future removal costs.

5. Severance Accounting

Exelon provides severance and health and welfare benefits to terminated employees pursuant to pre-existing severance plans primarily based upon each individual employee’s years of service with Exelon and compensation level. Exelon accounts for its ongoing severance plans in accordance with SFAS No. 112, “Employer’s Accounting for Postemployment Benefits, an amendment of FASB Statements No. 5 and 43” (SFAS No. 112) and SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” and accrues amounts associated with severance benefits that are considered probable and that can be reasonably estimated.

As part of the implementation of Exelon’s new business model referred to as The Exelon Way, during 2003, PECO identified 166 positions for elimination by the end of 2004. PECO recorded a charge for salary continuance severance of $16 million during 2003, which represented salary continuance severance costs that were probable and could be reasonably estimated as of December 31, 2003. During 2003, PECO recorded a charge of $4 million associated with special health and welfare severance benefits offered through The Exelon Way. In addition to cash and health and welfare severance benefits, PECO incurred curtailment costs associated with pension and postretirement benefit plans of $10 million as a result of personnel reductions due to The Exelon Way. In total, PECO recorded charges of $30 million in 2003 associated with The Exelon Way. See Note 10 – Retirement Benefits for a description of the curtailment charges for the pension and postretirement benefit plans.

PECO based its estimate of the number of positions to be eliminated on management’s current plans and its ability to determine the appropriate staffing levels to effectively operate the business. PECO may incur further severance costs associated with The Exelon Way if additional positions are identified for elimination. These costs will be recorded in the period in which the costs can be reasonably estimated.

183

PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

The following table details PECO’s total salary continuance severance expense recorded as an operating and maintenance expense within the Consolidated Statements of Income. During 2002 and 2001, no amounts were recorded as severance expense.


Salary continuance severance charges
Expense recorded - 2003	$	16
Expense recorded - 2002		—
Expense recorded - 2001		—

The following table provides a rollforward of PECO’s salary continuance severance obligation from January 1, 2003 through December 31, 2003. PECO had no severance charges or cash payments during 2002.


Salary continuance severance obligation
Balance as of January 1, 2003	$	—
Severance charges recorded		16
Cash payments		(2	)
Other adjustments		—

Balance as of December 31, 2003	$	14

6. Notes Payable and Short-Term Debt


	2003			2002			2001
Average borrowings	$	168		$	155		$	3
Maximum borrowings outstanding		582			612			471
Average interest rates, computed on a daily basis		1.23	%		1.77	%		2.99	%
Average interest rates, at December 31		1.02	%		1.51	%		2.25	%

At December 31, 2003, PECO’s aggregate sublimit under the credit agreements was $150 million. Sublimits under the credit agreements can change upon written notification to the bank group. PECO had approximately $48 million of unused bank commitments under the credit agreements at December 31, 2003. At December 31, 2003 and 2002, commercial paper outstanding was $46 million and $200 million, respectively. Interest rates on the advances under the credit facility are based on either the London Interbank Offering Rate (LIBOR) or prime plus an adder based on the credit rating of the borrower as well as the total outstanding amounts under the agreement at the time of borrowing. The maximum adder would be 175 basis points.

184

PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

7. Long-Term Debt


	December 31, 2003			December 31,
	Rates		Maturity Date	2003			2002
Securitized long-term debt (a)
PETT Transition Bonds Series 1999-A:
Fixed rates				$	—		$	2,426
Floating rates					—			274
PETT Transition Bonds Series 2000-A:					—			750
PETT Transition Bonds Series 2001:					—			805
Other long-term debt
First and Refunding Mortgage Bonds (b) (c):
Fixed rates	3.50%-6.63	%	2004-2012		1,002			1,000
Floating rates	1.08%-1.12	%	2012		154			154
Pollution control notes:
Fixed rates	5.20%-5.30	%	2021-2034		156			157
Floating rates					—			17
Notes payable – accounts receivable agreement	1.40	%	2005		49			61

Total long-term debt (d)					1,361			5,644
Unamortized debt discount and premium, net					(2	)		(4	)
Due within one year					—			(689	)

Long-term debt				$	1,359		$	4,951

Long-term debt to affiliates (a)
Subordinated debentures to PECO Trust IV	5.75	%	2033	$	103		$	—
Subordinated debentures to PECO Trust III	7.38	%	2028		81			—
Payable to PECO Energy Transitional Trust:
Series 1999-A
Fixed rates	5.80%-6.13	%	2004-2008		2,138			—
Floating rates	1.35%-1.42	%	2004-2007		155			—
Series 2000-A	7.63%-7.65	%	2009		750			—
Series 2001	6.52	%	2010		806			—

Total long-term debt to affiliates (e)					4,033			—
Long-term debt to affiliates due within one year					(153	)		—

Long-term debt to affiliates				$	3,880		$	—

(a)

Effective July 1, 2003, PECO Trust IV, a financing subsidiary created in May 2003, was deconsolidated from the financial statements of PECO in conjunction with the adoption of FIN No. 46. Effective December 31, 2003, PECO Trust III and PETT were deconsolidated from the financial statements in conjunction with the adoption of FIN No. 46-R. Amounts owed to PETT have been recorded as long-term debt to affiliate within the Consolidated Balance Sheets, and interest owed to PECO Trust IV has been recorded as interest expense to affiliates within the Consolidated Statements of Income.

(b)	Utility plant of PECO is subject to the lien of the PECO mortgage indenture.

(c)	Includes first mortgage bonds issued under the PECO mortgage indenture securing pollution control notes.

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PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

(d)	Long-term debt maturities in the period 2004 through 2008 and thereafter are as follows:


2004	$	—
2005		124
2006		—
2007		—
2008		452
Thereafter		785

Total	$	1,361

(e)	Long-term debt to affiliates maturities in the period 2004 through 2008 and thereafter are as follows:


2004	$	153
2005		434
2006		515
2007		645
2008		625
Thereafter		1,661

Total	$	4,033

During 2003, the following long-term debt was issued:


Type	Rate		Maturity	Amount
First and Refunding Mortgage Bonds	3.50	%	May 1, 2008	$	450
Long-term debt to PECO Trust IV	5.75	%	June 15, 2033		103

Total issuances				$	553

During 2003, payments were made on the following long-term debt:


Type	Rate		Maturity	Amount
First Mortgage Bonds	6.625	%	March 1, 2003	$	250
PECO Energy Transitional Trust	5.63	%	March 1, 2003		78
PECO Energy Transitional Trust	1.35	%	March 1, 2004		90
PECO Energy Transitional Trust	5.80	%	March 1, 2004		71
First Mortgage Bonds	6.50	%	May 1, 2003		200
Pollution Control Revenue Bonds	Variable		June 1, 2027		17

Total payments				$	706

See Note 11 – Fair Value of Financial Assets and Liabilities for additional information regarding interest-rate swaps. See Note 12 – Preferred Securities of Subsidiaries for additional information regarding mandatorily redeemable preferred securities and preferred stock.

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PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

8. Income Taxes

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


	For the Year Ended December 31,
	2003			2002			2001
Included in operations:
Federal
Current	$	257		$	305		$	255
Deferred		(15	)		(51	)		(49	)
Investment tax credit amortization		(2	)		(3	)		(3	)
State
Current		46			46			8
Deferred		(33	)		(38	)		(14	)

	$	253		$	259		$	197

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


	For the Year Ended December 31,
	2003		2002		2001
U.S. Federal statutory rate	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
Plant basis differences	(1.1	)	(1.5	)	(0.8	)
State income taxes, net of Federal income tax benefit	1.1		0.7		(0.6	)
Amortization of investment tax credit	(0.4	)	(0.3	)	(0.4	)
Other, net	0.2		0.9		(1.5	)

Effective income tax rate	34.8	%	34.8	%	31.7	%

The tax effects of temporary differences giving rise to significant portions of PECO’s deferred tax assets and liabilities as of December 31, 2003 and 2002 are presented below:


	2003			2002
Deferred tax liabilities:
Stranded cost recovery	$	1,784		$	1,923
Plant basis difference		1,253			1,138
Deferred investment tax credits		22			24
Deferred debt refinancing costs		20			22
Unrealized gain on derivative financial instruments		11			6

Total deferred tax liabilities		3,090			3,113

Deferred tax assets:
Deferred pension and postretirement obligations		(49	)		(44	)
Other, net		(97	)		(115	)

Total deferred tax assets		(146	)		(159	)

Deferred income tax liabilities (net) on the Consolidated Balance Sheets	$	2,944		$	2,954

187

PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

In accordance with regulatory treatment of certain temporary differences, PECO has recorded a net regulatory asset associated with deferred income taxes, pursuant to SFAS No. 71 and SFAS No. 109 “Accounting for Income Taxes,” of $762 million and $729 million at December 31, 2003 and 2002, respectively. See Note 15 – Supplemental Financial Information for further discussion of PECO’s regulatory asset associated with deferred income taxes.

Certain PECO tax returns are under review at the audit or 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 results of operations at PECO.

In 2003 and 2002, PECO received $7 million and $27 million, respectively, from Exelon related to PECO’s allocation of tax benefits under the Exelon Tax Sharing Agreement.

9. Nuclear Decommissioning

SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143) provides accounting requirements for retirement obligations (whether statutory, contractual or as a result of principles of promissory estoppel) associated with tangible long-lived assets. PECO was required to adopt SFAS No. 143 as of January 1, 2003.

In the case of the nuclear power plants formerly owned by PECO, the SFAS No. 143 ARO calculation yielded decommissioning obligations greater than the corresponding trust assets. As such, a regulatory asset of $20 million and a corresponding payable to Generation were recorded upon adoption of SFAS No. 143 at PECO. Due to additional contributions to and increases in the market value of the decommissioning trusts, as of December 31, 2003, the trust assets exceeded the ARO by $12 million. This amount was recorded as a regulatory liability with a corresponding receivable from Generation. Exelon believes that all of the decommissioning assets, including $29 million of annual collections from PECO ratepayers, which will increase to approximately $33 million beginning in 2004, will be used to decommission the former PECO plants. Exelon also expects the regulatory liability will be reduced to zero at the conclusion of the decommissioning of the former PECO plants. See Note 2 – Regulatory Issues for more information regarding the annual collections from PECO ratepayers.

10. 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. Substantially all PECO employees are eligible to participate in these plans. Benefits under these plans generally reflect each employee’s compensation, years of service, and age at retirement.

The prepaid pension asset and non-pension postretirement benefits obligation on PECO’s 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

188

PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

allocates the components of pension and postretirement benefits expense to the participating employers based upon several factors, including the percentage of active employees in each participating unit.

See Note 14 – Retirement Benefits of the Notes to Exelon’s Consolidated Financial Statements for pension and other postretirement benefits information for the Exelon plans.

Approximately $35 million, $22 million and $(2) million were included in operating and maintenance expense in 2003, 2002 and 2001, respectively, for PECO’s allocated portion of Exelon’s pension and postretirement benefit expense. PECO made pension and postretirement benefit contributions of $49 million annually in 2003 and 2002. PECO expects to contribute up to $8 million to the pension benefit plans in 2004.

During 2003, PECO recognized curtailment charges of $10 million associated with an overall reduction in participants in its pension and postretirement benefit plans due to employee reductions associated with The Exelon Way.

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 annually in 2003, 2002 and 2001.

11. Fair Value of Financial Assets and Liabilities

The carrying amounts and fair values of PECO’s financial assets and liabilities as of December 31, 2003 and 2002 were as follows:


	2003				2002
	Carrying Amount		Fair Value		Carrying Amount			Fair Value
Non-derivatives:
Liabilities
Long-term debt (including amounts due within one year) (a)	$	1,361	$	1,380	$	5,644		$	6,264
Long-term debt to PETT (including amounts due within one year) (a)		3,849		4,215		—			—
Long-term debt to affiliates (including amounts due within one year) (a)		184		189		—			—
Mandatorily redeemable preferred securities (a)		—		—		128			165
Derivatives:
Floating-to-fixed interest-rate swaps (a)	$	—	$	—	$	(22	)	$	(22	)

(a)

Effective July 1, 2003, PECO Trust IV was deconsolidated from the financial statements of PECO. Effective December 31, 2003, PETT and PECO Energy Capital Corp. were deconsolidated from the financial statements of PECO. The deconsolidation of these entities is in conjunction with the adoption of FIN No. 46-R. Amounts owed to PECO Trust IV, PETT and PECO Energy Capital Corp. were recorded as long-term debt to affiliate within the Consolidated Balance Sheets.

As of December 31, 2003 and 2002, 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 and mandatorily redeemable preferred securities are estimated based on quoted market prices for

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PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

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 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 2003, PECO had entered into forward-starting interest-rate swaps, with an aggregate notional amount of $360 million, in anticipation of the issuance of debt. These interest-rate swaps were designated as cash-flow hedges. In connection with bond issuances in 2003, PECO settled these forward-starting interest-rate swaps resulting in a $1 million pretax gain recorded in other comprehensive income, a component of shareholders’ equity, which is being amortized over the life of the related debt to interest expense.

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

As of December 31, 2003, $11 million of deferred net gains on derivative instruments accumulated in other comprehensive income are expected to be reclassified to interest expense 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.

At December 31, 2003 and 2002, the aggregate unamortized net gain on the settlements of swap transactions was $35 million and $41 million, respectively, recorded in accumulated other comprehensive income.

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 derivative 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.

190

PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

12. Preferred Securities

Preferred Stock

At December 31, 2003 and 2002, cumulative Preferred Stock of PECO, no par value, consisted of 15,000,000 shares authorized and the amounts set forth below:


	Current Redemption Price (a)			December 31,
				2003	2002	2003		2002
				Shares Outstanding		Dollar Amount
Series (without mandatory redemption)
$4.68 (Series D)	$	104.00		150,000	150,000	$	15	$	15
$4.40 (Series C)		112.50		274,720	274,720		27		27
$4.30 (Series B)		102.00		150,000	150,000		15		15
$3.80 (Series A)		106.00		300,000	300,000		30		30
$7.48		(b	)	—	500,000		—		50

Total preferred stock				874,720	1,374,720	$	87	$	137

(a)	Redeemable, at the option of PECO, at the indicated dollar amounts per share, plus accrued dividends.

(b)	Redeemed during 2003.

On June 11, 2003, PECO redeemed $50 million of its $7.48 preferred stock at a redemption price of $103.74 per share, plus accrued and unpaid dividends.

Mandatorily Redeemable Preferred Securities of a Partnership

At December 31, 2002, PECO Energy Capital, L.P. (Partnership), a Delaware limited partnership of which a wholly owned subsidiary of PECO is the sole general partner, had outstanding Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMPrS) as set forth in the following table:


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

Total						2,078,105	$	128

The securities issued by the PECO trusts represent COMPrS having a distribution rate and liquidation value equivalent to the trust securities. The COMPrS are the sole assets of these trusts and represent limited partnership interests of the Partnership. Each holder of a trust’s securities is entitled to withdraw the corresponding number of COMPrS from the trust in exchange for the trust securities so held. Each series of COMPrS 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 COMPrS.

Effective December 31, 2003, PECO Energy Capital Trust III was deconsolidated from the financial statements of PECO in conjunction with the adoption of FIN 46-R and $81 million of subordinated debentures issued by PECO to PECO Energy Trust III was recorded as long-term debt to affiliate within the Consolidated Balance Sheets. See “Variable Interest Entities” within Note 1 – Significant Accounting Policies for further information.

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PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

During June 2003, PECO issued $103 million of 5.75% deferrable interest subordinated debentures due 2033 to PECO Trust IV in connection with the issuance by PECO Trust IV of $100 million of 5.75% preferred securities that are mandatorily redeemable in 2033. Effective July 1, 2003, PECO Trust IV was deconsolidated from the financial statements of PECO in conjunction with the adoption of FIN No. 46 and $103 million of deferrable interest subordinated debentures issued by PECO to PECO Trust IV was recorded as long-term debt to affiliate within the Consolidated Balance Sheets. See Note 1 – New Accounting Principles and Accounting Changes for further information. The proceeds of the issue were used to redeem the trust preferred securities discussed below and the preferred stock as disclosed above.

Also on June 24, 2003, PECO Energy Capital Trust II, a financing subsidiary of PECO, redeemed $50 million of its 8.00% trust preferred securities at a redemption price of $25 per trust receipt, plus accrued and unpaid distributions.

Prior to the adoption of FIN No. 46-R the interest expense on the COMPrS was included in other income and deductions in the Consolidated Statements of Income. The interest expense is deductible for income tax purposes. Beginning January 1, 2004, PECO will begin recording interest associated with this debt in interest expense to affiliates.

The COMPrS issued by PECO Trust III have no voting privileges, except (i) for the right to approve a merger, consolidation or other transaction involving the Partnership that would result in a change in terms of the preferred securities, listing status on a national securities exchange, ratings by nationally recognized rating agencies, or rights of holders of the preferred securities, or that would result in certain federal income tax consequences, (ii) with respect to certain amendments to the Partnership agreement, (iii) for certain voting privileges that arise upon a default or deferral of interest under the deferrable interest subordinated debentures held by the Partnership or (iv) with respect to certain amendments to the related PECO guarantee agreement. The preferred securities issued by PECO Trust IV have no voting privileges, except (i) events of default under the deferrable interest subordinated debentures held by PECO Trust IV, (ii) an amendment of the trust agreement that would adversely affect the powers, preferences or privileges of the preferred securities, (iii) change the tax status of PECO Trust IV or (iv) with respect to certain amendments to the related PECO guarantee agreement.

13. Common Stock

At December 31, 2003 and 2002, common stock without par value consisted of 500,000,000 shares authorized and 170,478,507 shares outstanding.

Fund Transfer Restrictions.Under applicable law, PECO can pay dividends only from retained or current earnings. At December 31, 2003 PECO had retained earnings of $546 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 PECO Trust III and PECO Trust IV; (2) PECO defaults on its guarantee of the payment of distributions on the COMPrS

192

PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

issued by PECO Trust III or PECO Trust IV; or (3) an event of default occurs under the indentures under which the Subordinated Debentures are issued.

14. Commitments and Contingencies

Energy Commitments

In connection with the corporate restructuring, PECO entered into a purchased power agreement (PPA) with Generation. Under the terms of the PPA, PECO obtains the vast majority of its electric supply from Generation through 2010. The prices charged under the PPA were established by the Competition Act.

Commercial Commitments

PECO’s commercial commitments as of December 31, 2003 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
	Total		2004		2005-2006		2007-2008		2009 and beyond
Letters of credit (non-debt) (a)	$	29	$	29	$	—	$	—	$	—
Surety bonds (b)		24		24		—		—		—

Total commercial commitments	$	53	$	53	$	—	$	—	$	—

(a)	Letters of credit (non-debt) – PECO and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.

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

Environmental Issues

PECO’s operations have in the past and may in the future require substantial 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 27 sites where former manufactured gas plant (MGP) activities have or may have resulted in actual site contamination. Of these 27 sites, the Pennsylvania Department of Environmental Protection has approved the clean-up of six sites. 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, 2003 and 2002, PECO had accrued $50 million and $40 million, respectively, for environmental investigation and remediation costs, including $41 million and $28 million, respectively (reflecting discount rates of 5.0% and 4.6%, respectively), for investigation and remediation at its 27 MGP sites, that currently can be reasonably estimated. Such estimates, reflecting the effects of a 2.5% and 1.6% inflation rate before the effects of discounting were $44 million and $58 million at December 31, 2003 and 2002, respectively. PECO cannot reasonably estimate whether it will incur other significant liabilities for additional

193

PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

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. However, PECO is currently recovering through regulated gas rates costs associated with the remediation of the MGP sites.

As of December 31, 2003, PECO anticipates that payments related to the discounted environmental investigation and remediation costs, recorded on an undiscounted basis were:


2004	$	9
2005		10
2006		12
2007		1
2008		2
Remaining years		10

Total payments	$	44

In December 2003, PECO updated its accounting estimate related to the reserve for environmental remediation. Based on an independently prepared environmental remediation study of MGP sites, PECO increased its environmental reserve by $18 million, with a corresponding increase to the MGP regulatory asset. See Note 15 – Supplemental Financial Information for further discussion of the MGP regulatory asset.

Leases

Minimum future operating lease payments, which consist primarily of lease payments for vehicles, as of December 31, 2003 were:


2004	$	4
2005		3
2006		3
2007		1
2008		1
Remaining years		2

Total minimum future lease payments	$	14

Rental expense under operating leases totaled $6 million, $7 million, and $2 million in 2003, 2002, and 2001, respectively.

Litigation

Real Estate Tax Appeals. PECO is challenging real estate taxes assessed on nuclear plants since 1997. PECO is involved in litigation in which it is contesting taxes assessed in 1997 under the Pennsylvania Public Utility Realty Tax Act of March 4, 1971, as amended (PURTA) and has appealed local real estate assessments for 1998 and 1999 on its formerly owned Limerick Generating Station (Montgomery County, PA) (Limerick) and Peach Bottom Atomic Power Station (York County, PA) (Peach Bottom) plants.

During 2003, upon completion of updated nuclear plant appraisal studies, PECO recorded reductions of $58 million to reserves recorded for exposures associated with the real estate taxes. While PECO believes the resulting reserve balances as of December 31, 2003 reflect the most likely probable expected outcome of the

194

PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

litigation and appeals proceedings in accordance with SFAS No. 5, “Accounting for Contingencies,” the ultimate outcome of such matters could result in additional unfavorable or favorable adjustments to the consolidated financial statements of PECO, and such adjustments could be material

General. PECO is involved in various other litigation matters that are being defended and handled in the ordinary course of business, and PECO maintains accruals for such costs that are probable of being incurred and subject to reasonable estimation. The ultimate outcome of such matters, as well as the matters discussed above, are uncertain and may have a material adverse effect on PECO’s financial condition or results of operations.

Capital Commitments

PECO estimates that it will spend approximately $239 million for capital expenditures in 2004.

Income Tax Refund Claims

PECO has entered into several agreements with a tax consultant related to the filing of refund claims with the IRS and has made refundable prepayments of $5 million ($1 million during 2003 and $4 million in prior periods) for potential fees associated with these agreements. The fees for these agreements are contingent upon a successful outcome and are based upon a percentage of the refunds recovered from the IRS, if any. As such, ultimate net cash outflows to PECO related to these agreements will either be positive or neutral depending upon the outcome of the refund claim with the IRS. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of PECO. PECO cannot predict the timing of the final resolution of these refund claims.

Derivatives

15. Supplemental Financial Information

Supplemental Income Statement Information


	For the Years Ended December 31,
	2003		2002		2001
Depreciation and amortization:
Property, plant and equipment (a)	$	144	$	141	$	135
Competitive transition charge		336		308		275
DOE facility decommissioning		7		7		6

Total depreciation and amortization	$	487	$	456	$	416

(a)	Includes amortization of capitalized software costs.

195

PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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


	For the Years Ended December 31,
	2003			2002			2001
Taxes other than income
Utility (a)	$	206		$	207		$	135
Real estate (b)		(47	)		27			12
Payroll		11			13			12
Other		3			(3	)		2

Total	$	173		$	244		$	161

(a)	Represents municipal and state utility taxes which are also recorded in revenues on PECO’s Consolidated Statements of Income.

(b)	Includes the reversal of $58 million property tax accrual during 2003 as described in Note 14 – Commitments and Contingencies.


	For the Years Ended December 31,
	2003			2002		2001
Other, net
Investment income	$	10		$	26	$	24
AFUDC		1			1		2
Gain (loss) on disposition of assets, net		—			1		6
Other income (expense)		(9	)		3		4

Total	$	2		$	31	$	36

Supplemental Cash Flow Information


	For the Years Ended December 31,
	2003		2002		2001
Cash paid during the year:
Interest (net of amount capitalized)	$	346	$	379	$	416
Income taxes (net of refunds)		269		388		271
Non-cash investing and financing:
Contribution of receivable from parent	$	—	$	—	$	1,878
Net assets transferred as a result of the corporate restructuring		—		—		1,608

196

PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

Supplemental Balance Sheet Information


	December 31,
	2003			2002
Regulatory assets (liabilities)
Competitive transition charge	$	4,303		$	4,639
Deferred income taxes (see Note 8 – Income Taxes)		762			729
Non-pension postretirement benefits		58			64
Reacquired debt costs		49			53
MGP regulatory asset (see Note 14 – Commitments and Contingencies)		34			20
DOE facility decommissioning		26			32
Nuclear decommissioning (see Note 9 – Nuclear Decommissioning)		(12	)		—
Other		6			9

Long-term regulatory assets		5,226			5,546
Deferred energy costs (current asset)		81			31

Total	$	5,307		$	5,577

Competitive Transition Charge. These charges represent PECO’s stranded costs that the PUC determined would be allowed to be recoverable through regulated rates. These costs are related to the deregulation of the generation portion of the electric utility business in Pennsylvania. The CTC includes intangible transition property sold to PETT, a wholly owned subsidiary of PECO, in connection with the securitization of PECO’s stranded cost recovery. These charges are being amortized through December 31, 2010 with a return on the unamortized balance of 10.75%.

Deferred Income Taxes. These costs represent the difference between the method in which the regulator allows for the recovery of income taxes and how income taxes would be recorded by unregulated entities. These regulatory assets and liabilities associated with deferred income taxes, recorded in compliance with SFAS No. 71 and SFAS No. 109, 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 or settlement of these costs in future rates.

Non-pension Postretirement Benefits.These costs are the result of transitioning to SFAS No. 106 in 1993, which are recoverable in regulated rates through 2012.

Reacquired Debt Costs. These costs represent premiums paid for the early extinguishment and refinancing of long-term debt, which is amortized over the life of the new debt issued to finance the debt redemption.

MGP Regulatory Asset. These costs represent estimated environmental remediation costs which are recoverable through regulated gas rates. PECO has identified 27 sites where former MGP activities have or may have resulted in site contamination.

DOE Facility Decommissioning. These costs represent PECO’s share of recoverable decommissioning and decontamination costs of the Department of Energy’s (DOE) nuclear fuel enrichment facilities established by the National Energy Policy Act of 1992.

Nuclear Decommissioning Costs. Generation is responsible for decommissioning the nuclear plants formerly owned by PECO. These costs represent the amount of estimated present value of future nuclear

197

PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

decommissioning costs that are less than the associated decommissioning trust fund assets. PECO believes the trust fund assets including any future collections from ratepayers will equal the associated future decommissioning costs. See Note 9 – Nuclear Decommissioning.

Deferred Energy Costs (Current Asset). These costs represent fuel costs recoverable under the purchase gas adjustment clause.

Recovery/Settlement of Regulatory Assets and Liabilities.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. Therefore, this cost is earning a rate of return.


	December 31,
	2003		2002
Accrued expenses
Taxes accrued	$	110	$	116
Interest accrued		14		112
Other accrued expenses		113		104

	$	237	$	332

16. Related-Party Transactions

PECO’s financial statements include related-party transactions with its unconsolidated subsidiaries as reflected in the table below.


	For Year Ended December 31,
	2003		2002		2001
Interest expense from affiliates
PECO Energy Capital Trust IV (1)	$	3	$	—	$	—


	December 31,
	2003		2002
Investment in subsidiaries
PECO Energy Capital Corp (1)	$	16	$	—
PECO Energy Capital Trust IV (1)		3		—
Receivables from affiliates (non-current)
PECO Energy Transitional Trust (1)		105		—
Payables to affiliates
PECO Energy Capital Corp (1)		1		—
PECO Energy Capital Trust III (1)		10		—
Long-term debt to affiliates (including due within one year)
PECO Energy Transitional Trust (1)		3,849		—
PECO Energy Capital Trust IV (1)		103		—
PECO Energy Capital Trust III (1)		81		—

(1)

Effective July 1, 2003 PECO Energy Capital Trust IV was deconsolidated from the financial statements of PECO in conjunction with the adoption of FIN 46. Effective December 31, 2003, PECO Energy Transitional Trust, PECO Energy Capital Corporation, and PECO Energy Capital Trust III were deconsolidated from the financial statements of PECO in conjunction with the adoption of FIN 46-R.

198

PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

In addition to the transactions described above, PECO’s financial statements include related-party transactions as reflected in the tables below.


	For Year Ended December 31,
	2003		2002		2001
Operating revenues from affiliate
Generation (1)	$	10	$	12	$	12
Other		1		—		—
Purchased power from affiliate
Generation (2)		1,433		1,438		1,162
O&M from affiliates
BSC (4)		50		49		69
Enterprises (5)		2		24		24
ComEd (9)		5		—		—
Capitalized costs
Enterprises (5)		15		24		29
BSC (4)		4		8		—
Interest expense from affiliates
ComEd (6)		—		—		8
Interest income from affiliates
Generation (7)		—		—		6
Other		—		—		4
Cash dividends paid to parent		322		340		342


	December 31,
	2003		2002
Receivable from affiliate (noncurrent)
Generation (8)	$	12	$	—
Payables to affiliates (current)
Generation (2)		115		124
BSC (4)		15		26
Enterprises (5)		—		19
ComEd (9)		6		—
Other		3		1
Shareholders’ equity – receivable from parent (10)		1,623		1,758

(1)	PECO provides energy to Generation for Generation’s own use.

(2)	Effective January 1, 2001, PECO entered into a PPA with Generation.

(4)

PECO provides services to BSC related to invoice processing. PECO receives a variety of corporate support services from BSC, including legal, human resources, financial and information technology services. Such services are provided at cost, including applicable overhead. Some of these costs are capitalized.

(5)	PECO receives services from Enterprises for construction, which are capitalized, and the deployment of automated meter reading technology, which is expensed.

(6)	At December 31, 2000, PECO had a $400 million payable to ComEd, which was repaid in the second quarter of 2001. The average annual interest rate on this payable for the period outstanding was 6.5%.

(7)	PECO received interest income from Generation in 2001 related to a loan which was repaid in 2001.

199

PECO Energy Company and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

(8)	PECO has a receivable to Generation related to a regulatory liability as a result of the adoption of SFAS No. 143. See Note 9 – Nuclear Decommissioning for further information.

(9)	In 2003, PECO received relief from ComEd workers during Hurricane Isabel.

(10)	PECO has a non-interest bearing receivable from Exelon related to the 2001 corporate restructuring. The receivable is expected to be settled over the years 2004 through 2010.

17. Quarterly Data (Unaudited)

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


	Operating Revenues				Operating Income				Net Income on Common Stock
	2003		2002		2003		2002		2003		2002
Quarter ended:
March 31	$	1,217	$	1,020	$	282	$	227	$	135	$	87
June 30		961		995		224		234		86		91
September 30		1,149		1,224		301		323		140		155
December 31		1,061		1,094		249		309		107		145

200

Generation

Report of Independent Auditors

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 (Generation) at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, 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 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 1 to the consolidated financial statements, Generation changed its method of accounting for derivative instruments and hedging activities as of January 1, 2001, its method of accounting for goodwill as of January 1, 2002, and its method of accounting for asset retirement obligations as of January 1, 2003.

PricewaterhouseCoopers LLP

Chicago, Illinois

January 28, 2004

201

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Income


	For the Year Ended December 31,
(in millions)	2003			2002			2001
Operating revenues
Operating revenues	$	4,010		$	2,631		$	2,723
Operating revenues from affiliates		4,125			4,227			4,103

Total operating revenues		8,135			6,858			6,826

Operating expenses
Purchased power		3,158			2,980			2,924
Purchased power from affiliates		429			314			182
Fuel		1,533			959			889
Impairment of Boston Generating, LLC long-lived assets		945			—			—
Operating and maintenance		1,796			1,504			1,400
Operating and maintenance from affiliates		149			152			128
Depreciation and amortization		199			276			282
Taxes other than income		120			164			149

Total operating expense		8,329			6,349			5,954

Operating income (loss)		(194	)		509			872

Other income and deductions
Interest expense		(75	)		(68	)		(77	)
Interest expense from affiliates		(13	)		(7	)		(38	)
Equity in earnings of unconsolidated affiliates		49			87			90
Interest income from affiliates		1			6			12
Other, net		(188	)		77			(20	)

Total other income and deductions		(226	)		95			(33	)


Income (loss) before income taxes and cumulative effect of changes in accounting principles		(420	)		604			839

Income taxes		(179	)		217			327

Income (loss) before cumulative effect of changes in accounting principles		(241	)		387			512

Cumulative effect of changes in accounting principles (net of income taxes of $70, $9 and $7, respectively)		108			13			12

Net income (loss)	$	(133	)	$	400		$	524

See Notes to Consolidated Financial Statements

202

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Cash Flow


	For the Year Ended December 31,
(in millions)	2003			2002			2001
Cash flows from operating activities
Net income (loss)	$	(133	)	$	400		$	524
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel		783			640			682
Cumulative effect of changes in accounting principles (net of income taxes)		(108	)		(13	)		(12	)
Impairment of investment		255			—			—
Impairment of long-lived assets		952			—			—
Deferred income taxes and amortization of investment tax credits		(249	)		132			23
Provision for uncollectible accounts		(2	)		26			16
Loss on sale of investments		25			—			—
Equity in earnings of unconsolidated affiliates		(49	)		(87	)		(90	)
Net realized losses on nuclear decommissioning trust funds		16			32			127
Other operating activities		6			75			69
Changes in assets and liabilities:
Accounts receivable		(71	)		(263	)		142
Changes in receivables and payables to affiliates, net		195			(72	)		7
Inventories		(29	)		(33	)		(28	)
Other current assets		(35	)		(71	)		3
Accounts payable, accrued expenses and other current liabilities		11			370			26
Pension and non-pension postretirement benefits obligations		(50	)		(60	)		(116	)
Other noncurrent assets and liabilities		(64	)		74			(99	)

Net cash flows provided by operating activities		1,453			1,150			1,274

Cash flows from investing activities
Capital expenditures		(953	)		(990	)		(858	)
Proceeds from liquidated damages		92			—			—
Proceeds from nuclear decommissioning trust funds		2,341			1,612			1,624
Investment in nuclear decommissioning trust funds		(2,564	)		(1,824	)		(1,863	)
Acquisition of businesses, net of cash acquired		(272	)		(445	)		—
Note receivable from unconsolidated affiliates		35			(35	)		14
Proceeds from sales of investments		82			—			—
Change in restricted cash		(63	)		(12	)		—
Other investing activities		1			8			40

Net cash flows used in investing activities		(1,301	)		(1,686	)		(1,043	)

Cash flows from financing activities
Issuance of long-term debt		1,066			30			821
Retirement of long-term debt		(570	)		(5	)		(4	)
Change in note payable, affiliate		87			329			(696	)
Payment on acquisition note to Sithe Energies, Inc.		(446	)		—			—
Distribution to member		(189	)		(27	)		(132	)
Contribution from minority interest of consolidated subsidiary		—			43			—

Net cash flows (used in) provided by financing activities		(52	)		370			(11	)

Increase (decrease) in cash and cash equivalents		100			(166	)		220
Cash and cash equivalents at beginning of period		58			224			4

Cash and cash equivalents at end of period	$	158		$	58		$	224

See Notes to Consolidated Financial Statements

203

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(in millions)	2003			2002
Assets
Current assets
Cash and cash equivalents	$	158		$	58
Restricted cash		75			12
Accounts receivable, net
Customer		711			587
Other		112			57
Receivables from affiliates		421			594
Inventories, at average cost
Fossil fuel		98			97
Materials and supplies		259			217
Note receivable		5			—
Assets held for sale		36			—
Deferred income taxes		445			7
Other		233			176

Total current assets		2,553			1,805

Property, plant and equipment, net		7,106			4,698
Deferred debits and other assets
Nuclear decommissioning trust funds		4,721			3,053
Investments		65			657
Receivable from affiliate		22			220
Deferred income taxes		—			271
Prepaid pension asset		79			—
Other		218			201

Total deferred debits and other assets		5,105			4,402

Total assets	$	14,764		$	10,905

Liabilities and member’s equity
Current liabilities
Long-term debt due within one year	$	1,068		$	5
Accounts payable		1,429			1,126
Payables to affiliates		1			10
Notes payable to affiliates		506			863
Accrued expenses		434			482
Other		126			108

Total current liabilities		3,564			2,594

Long-term debt		1,649			2,132
Deferred credits and other liabilities
Unamortized investment tax credits		218			226
Nuclear decommissioning liability for retired plants		—			1,293
Asset retirement obligation		2,996			—
Pension obligation		21			37
Non-pension postretirement benefits obligation		555			410
Spent nuclear fuel obligation		867			858
Deferred income taxes		299			—
Payables to affiliates		1,195			—
Other		441			402

Total deferred credits and other liabilities		6,592			3,226

Total liabilities		11,805			7,952

Commitments and contingencies
Minority interest of consolidated subsidiary		3			54

Member’s equity
Membership interest		2,490			2,296
Undistributed earnings		602			924
Accumulated other comprehensive loss		(136	)		(321	)

Total member’s equity		2,956			2,899

Total liabilities and member’s equity	$	14,764		$	10,905

See Notes to Consolidated Financial Statements

204

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Changes in Divisional/Member’s Equity


(in millions)	Divisional Equity			Membership Interest			Undistributed Earnings			Accumulated Other Comprehensive Income (Loss)			Total Member’s Equity
Balance, December 31, 2000	$	2,610		$	—		$	—		$	—		$	2,610
Formation of LLC		(2,610	)		2,610			—			—			—
Net income		—			—			524			—			524
Non-cash distribution to member		—			(163	)		—			—			(163	)
Distribution to member		—			(132	)		—			—			(132	)
Reclassified net unrealized losses on marketable securities, net of income taxes of $(22)		—			—			—			(23	)		(23	)
Other comprehensive income, net of income taxes of $(16)		—			—			—			(8	)		(8	)

Balance, December 31, 2001		—			2,315			524			(31	)		2,808

Net income		—			—			400			—			400
Distribution to member		—			(30	)		—			—			(30	)
Allocation of tax benefit from member		—			11			—			—			11
Other comprehensive income, net of income taxes of $(223)		—			—			—			(290	)		(290	)

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

Net income		—			—			(133	)		—			(133	)
Non-cash distribution to member		—			(17	)		—			—			(17	)
Distribution to member		—			—			(189	)		—			(189	)
Cumulative effect of FAS 143 adoption		—			210			—			—			210
Contribution from member		—			1			—			—			1
Other comprehensive income, net of income taxes of $179		—			—			—			185			185

Balance, December 31, 2003	$	—		$	2,490		$	602		$	(136	)	$	2,956

See Notes to Consolidated Financial Statements

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Consolidated Statements of Comprehensive Income


	For the Years Ended December 31,
(in millions)	2003			2002			2001
Net income (loss)	$	(133	)	$	400		$	524

Other comprehensive income (loss)
SFAS No. 133 transition adjustment, net of income taxes of $3	$	—		$	—		$	5
SFAS No. 143 transition adjustment, net of income taxes of $167		168			—			—
Cash-flow hedge fair value adjustment, net of income taxes of $(17), $(108) and $29, respectively		(27	)		(170	)		48
Unrealized gain (loss) on marketable securities, net of income taxes of $4, $(110) and $(31), respectively		2			(113	)		(32	)
Realized loss on forward-starting interest-rate swap net of income taxes of $(1)		—			—			(2	)
Interest in other comprehensive income of unconsolidated affiliates, net of income taxes of $25, $(5) and $(16), respectively		42			(7	)		(27	)

Total other comprehensive income (loss)		185			(290	)		(8	)

Total comprehensive income	$	52		$	110		$	516

See Notes to Consolidated Financial Statements

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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. Generation has numerous wholly owned subsidiaries. These subsidiaries were primarily established to hold certain hydro-electric, intermediate, and peaking-unit facilities, as well as the 50% interest in Sithe Energies, Inc. (Sithe). In addition, Generation also has a finance company subsidiary, Generation Finance Company, LLC, which provides certain financing for Generation’s other subsidiaries.

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 plants are consolidated. Investments in which less than a 20% interest is owned are primarily accounted for under the cost method of accounting.

Generation owns 100% of all significant consolidated subsidiaries, either directly or indirectly, except for Southeast Chicago Energy Project, LLC (Southeast Chicago) of which Generation owns 74%. Generation has reflected the third-party interests in the above majority-owned investment as minority interests in its Consolidated Statements of Cash Flows, Consolidated Balance Sheets and in other, net on the Consolidated Statements of Income. In conjunction with the adoption of Statement of Financial Accounting Standards (SFAS) No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (SFAS No. 150) on July 1, 2003, Generation reclassified the minority interest associated with Southeast Chicago to a long-term liability. The total minority interest related to Southeast Chicago was $51 million as of December 31, 2003. Prior periods were not restated.

Reclassifications

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

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States (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 derivatives, nuclear decommissioning, fixed asset depreciation, asset impairments, severance, pension and other postretirement benefits, taxes, unbilled energy revenues and environmental costs.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

Variable Interest Entities

The Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” in January 2003 and issued its revision in FASB Interpretation No. 46-R, “Consolidation of Variable Interest Entities” (FIN No. 46-R) in December 2003, which addressed the requirements for consolidating certain variable interest entities. FIN No. 46-R will be effective for Generation’s variable interest entities as of March 31, 2004.

Based upon management’s interpretation of FIN No. 46-R, it is reasonably possible that Generation will consolidate Sithe as of March 31, 2004. Generation is a 50% owner of Sithe and accounts for this entity as an unconsolidated equity investment. Sithe owns and operates power-generating facilities. See Note 3 – Sithe for a further discussion of Generation’s investment in Sithe.

Revenues

Operating Revenues.Operating revenues are generally recorded as service is rendered or energy is delivered to customers. At the end of each month, Generation accrues an estimate for the unbilled amount of energy delivered or services provided to its electric customers.

Option Contracts, Swaps, and Commodity Derivatives.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.

Trading Activities.In the third quarter of 2002, Generation adopted the provisions of Emerging Issues Task Force (EITF) Issue No. 02-3, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3) which required 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 activity were presented in revenue and the energy costs related to energy trading were presented as either purchased power or fuel expense in Generation’s Consolidated Statements of Income. For comparative purposes, energy costs related to energy trading have been reclassified in prior periods to conform to the net basis of presentation required by EITF 02-3. Generation commenced trading activities in April 2001. For the year ended December 31, 2001, $207 million of purchased power expense and $15 million of fuel expense were reclassified and reflected as a reduction to revenue.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

Stock-Based Compensation

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). Exelon adopted the additional disclosure requirements of SFAS No. 148 in 2002 and continues to account for its stock-compensation plans under the disclosure-only provision 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, 2003, 2002 and 2001:


	2003			2002		2001
Net income (loss) – as reported	$	(133	)	$	400	$	524
Deduct: total stock-based compensation expense determined under fair value based method for all awards, net of income taxes		3			15		9

Pro forma net income (loss)	$	(136	)	$	385	$	515

Income Taxes

Deferred Federal and state income taxes are provided on all significant temporary differences between the book basis and the tax basis of assets and liabilities. Investment tax credits previously utilized for income tax purposes have been deferred on the Consolidated Balance Sheets and are recognized in book income over the life of the related property. Generation and its subsidiaries file a consolidated return with Exelon for Federal and certain state income tax returns. Income taxes of the Exelon consolidated group are allocated to Generation based on the separate return method. Generation estimates its income tax valuation allowance by assessing which deferred tax assets are more likely than not to be recovered in the future (see Note 9 – Income Taxes).

Generation is a party to an agreement (the “Tax Sharing Agreement”) that provides for the allocation of consolidated tax liabilities. The Tax Sharing Agreement generally provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to other members. That allocation is treated as a contribution to the capital of the party receiving the benefit.

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.

Cash and Cash Equivalents

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

Restricted Cash

As of December 31, 2003, restricted cash primarily represents liquidated damages receipts which is restricted as to use for the construction of the Exelon New England facilities.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

Accounts Receivable and Allowance for Doubtful Accounts

Customer accounts receivable included $366 million and $394 million of unbilled operating revenues related to amounts of energy delivered to customers in the months of December 2003 and 2002, respectively. The allowance for doubtful accounts reflects Generation’s best estimate of probable losses inherent in the accounts receivable balance. The allowance is based on known troubled accounts, historical experience, and other currently available evidence.

In December 2002, Generation increased its allowance for uncollectible accounts by $6 million based on an independently prepared evaluation of the risk profile of Power Team’s counterparties. Power Team is the unit within Generation that manages the output of Generation’s assets and energy sales.

Inventories

Fossil Fuel. Fossil fuel inventory includes the weighted average cost of coal, oil, and stored natural gas. The costs of coal, oil and gas are generally charged to inventory when purchased and used. These balances are carried at the lower of cost or market.

Materials and Supplies. Materials and supplies inventory generally includes the average costs of generating plant materials. Materials are generally charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. Provisions are made for obsolete inventory.

Emission Allowances

Emission allowances are included in inventories and deferred debits and other assets and are carried at the lower of cost or market and charged to fuel expense as they are used in operations. Allowances held can be used from years 2004 to 2028. Generation’s emission allowances balance as of December 31, 2003 and 2002 was $105 million and $107 million, respectively.

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, on nuclear decommissioning trust funds transferred to Generation from PECO and ComEd are reflected in the payables to affiliates on Generation’s Consolidated Balance Sheets. Unrealized gains and losses on nuclear decommissioning trust funds for units acquired after the Merger are reported in other comprehensive income. Prior to the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143) on January 1, 2003, unrealized gains and losses on marketable securities held in the nuclear decommissioning trust funds were reported in accumulated depreciation for operating units transferred to Generation from PECO and as other comprehensive income for operating and retired units transferred to Generation from ComEd. At December 31, 2003 and 2002, Generation had no held-to-maturity securities.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost. The cost of maintenance, repairs and minor replacements of property is charged to maintenance expense as incurred.

Nuclear Fuel

The cost of nuclear fuel is capitalized and charged to fuel expense using the unit-of-production method. Estimated costs of nuclear fuel storage and disposal, exclusive of dry cask storage costs, at operating plants are charged to fuel expense as the related fuel is consumed. Costs associated with nuclear outages are recorded in the period incurred. Dry cask storage costs are expensed as incurred.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

Capitalized Software Costs

Costs incurred during the application development stage of software that is developed or obtained for internal use are capitalized. At December 31, 2003, 2002, and 2001, unamortized capitalized software costs totaled $42 million, $28 million, and $19 million, respectively. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, not to exceed ten years. During 2003, 2002 and 2001, Generation amortized capitalized software costs of $8 million, $10 million and $4 million, respectively.

Depreciation and Amortization

Depreciation is provided over the estimated service lives of property, plant and equipment on a straight-line basis using the composite method. Annual depreciation provisions for financial reporting purposes, expressed as a percentage of average service life for electric generating assets, are presented in the table below. See Changes in Accounting Estimates below for information on service life extensions for certain nuclear generating stations.


Asset Category	2003		2002		2001
Electric-generation	3.11	%	3.65	%	3.11	%

Nuclear Generating Station Decommissioning

Generation accounts for the costs of decommissioning its nuclear generating stations in accordance with SFAS No. 143. See Note 10 – Nuclear Decommissioning and Spent Fuel Storage for information regarding the adoption and application of SFAS No. 143 and Cumulative Effect of Changes in Accounting Principle below for pro forma net income for the years ended December 31, 2002 and 2001, adjusted as if SFAS No. 143 had been applied effective January 1, 2001.

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 $15 million, $24 million, and $17 million in 2003, 2002, and 2001, respectively.

Asset Impairments

Long-Lived Assets.Generation evaluates the carrying value of long-lived assets to be held and used for impairment whenever indications of impairment exist in accordance with the requirements of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144). The carrying value of long-lived assets is considered impaired when the projected undiscounted cash flows are less than the carrying value. In that event, a loss would be recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by available market valuations or, if applicable, discounted cash flows. See Note 2 – Acquisitions and Dispositions for a description of the impairment recorded in 2003 related to the long-lived assets of Boston Generating, LLC (Boston Generating), formerly known as Exelon Boston Generating, LLC.

Upon the decision to exit or sell a long-lived asset or group of assets, the carrying value of these assets is adjusted downward, if necessary, to the estimated sales price, less cost to sell. The assets and associated liabilities that are part of a disposal group are classified as held for sale. See Note 2 – Acquisitions and Disposition for a description of assets and liabilities classified as held for sale as of December 31, 2003.

Investments.Investments are considered to be impaired when a decline in fair value is judged to be other-than-temporary. If the cost of an investment exceeds its fair value, Generation evaluates, among other factors,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

general market conditions, the duration and extent to which the fair value is less than cost, as well as its intent and ability to hold the investment. Generation also considers specific adverse conditions related to the financial health of and business outlook for the investee. Once a decline in fair value is determined to be other-than-temporary, an impairment charge is recorded and a new cost basis is established. See Note 3 – Sithe for a description of the impairments recorded in 2003 related to Generation’s investment in Sithe.

Derivative Financial Instruments

Generation adopted SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133) on January 1, 2001. As a result, 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.

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 derivatives recorded at fair value are recognized in earnings unless specific hedge accounting criteria are met, in which case those changes are recorded in other comprehensive income. 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. Gains and losses on these contracts are recognized when the underlying physical transaction affects earnings. 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 thus not required to be recorded at fair value, but on an accrual basis of accounting.

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, 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. Generation utilizes derivatives with respect to energy transactions 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 energy-related derivatives for trading purposes. 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. Commitments under these contracts are discussed in Note 13 – Commitments and Contingencies.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

Generation enters 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.

Cumulative Effect of Changes in Accounting Principles

The following tables set forth Generation’s net income for the years ended December 31, 2003, 2002 and 2001, adjusted as if SFAS No. 143 had been applied effective January 1, 2001. SFAS No. 143 was adopted as of January 1, 2003.


	2003			2002		2001
Reported net income (loss)	$	(133	)	$	400	$	524
Earnings effect of adopting SFAS No. 143		—			27		66

Adjusted net income (loss)	$	(133	)	$	427	$	590

See Note 10 – Nuclear Decommissioning and Spent Fuel Storage for further information regarding the adoption of SFAS No. 143.

Generation changed its method of accounting for goodwill in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142) on January 1, 2002 and recognized a cumulative effect of change in accounting principles of $13 million, net of taxes related to goodwill at its then 50% owned affiliate AmerGen.

New Accounting Pronouncements

Through Exelon’s postretirement benefit plans, Generation provides retirees with prescription drug coverage. On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Prescription Drug Act) was enacted. The Prescription Drug Act introduced a prescription drug benefit under Medicare as well as a Federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. In response to the enactment of the Prescription Drug Act, the FASB issued FASB Staff Position (FSP) FAS 106-1 (FSP FAS 106-1) in January 2004, which permits a plan sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer the accounting for the effects of the Prescription Drug Act. Exelon has made the one-time election allowed by FSP FAS 106-1. Thus, Generation’s financial statements and Note 11 – Retirement Benefits do not reflect the effects of the Prescription Drug Act on Generation’s allocated portion of Exelon’s postretirement plans. Exelon is evaluating what impact the Prescription Drug Act will have on its postretirement benefit plans and whether it will be eligible for a Federal subsidy beginning in 2006. Specific authoritative guidance on the accounting for the Federal subsidy is pending, and that guidance, when issued, could require Generation to change previously reported information. Generation will adopt this standard effective January 1, 2004.

In July 2003, the EITF reached a consensus on EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, ‘Accounting for Derivative Instruments and Hedging Activities,’ and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3 ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” (EITF 03-11), which was ratified by the FASB in August 2003. The EITF concluded that determining whether realized gains and losses on physically settled derivative contracts not “held for trading purposes” should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. The impact, if any, of adopting EITF 03-11 on Generation’s operating revenues and operating expenses has not been determined but could be material. The adoption of EITF 03-11 will have no impact on net income.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

As discussed above, FIN No. 46-R will be effective for Generation’s variable interest entities as of March 31, 2004. Generation believes that it is reasonably possible that it will consolidate Sithe as of March 31, 2004. Generation contractually does not own any interest in Sithe International, a subsidiary of Sithe. As such, a portion of Sithe’s net assets and results of operations would be eliminated from Generation’s Consolidated Balance Sheets and Consolidated Statements of Income through a minority interest if Sithe is consolidated under FIN No. 46-R as of March 31, 2004. See Note 3 – Sithe for additional information regarding Generation’s investment in Sithe.

Generation continues to review other entities with which Generation and its subsidiaries have business arrangements to determine if those entities are variable interest entities under FIN No. 46-R and, if so, whether consolidation of these entities will be required as of March 31, 2004.

2. Acquisitions and Dispositions

AmerGen Energy Company, LLC

On December 22, 2003, Generation purchased British Energy plc’s (British Energy) 50% interest in AmerGen for $276.5 million.

Prior to the purchase, Generation was a 50% owner of AmerGen and had accounted for the investment as an unconsolidated equity investment. From January 1, 2003 through the date of closing, Generation recorded $47 million of equity in earnings of unconsolidated affiliates related to its investment in AmerGen and had significant purchased power agreements (PPAs) with AmerGen. The book value of Generation’s investment in AmerGen prior to the purchase was $311 million.

The transaction was accounted for as a step acquisition. As such, upon consolidation, Generation was required to allocate its $311 million book value as discussed above to 50% of AmerGen’s equity balance. The difference between Generation’s investment in AmerGen and 50% of AmerGen’s equity book value of approximately $227 million was primarily due to Generation not recognizing a significant portion of the cumulative effect of the change in accounting principle at AmerGen related to the adoption of SFAS No. 143. Generation reduced AmerGen’s equity value through the reduction of the book value of AmerGen’s long-lived assets.

Generation recorded the acquired assets and liabilities of AmerGen (remaining 50%) to fair value as of the date of purchase. The following assets and liabilities, reflecting the equity basis and fair value adjustments discussed above, of AmerGen were recorded within Generation’s Consolidated Balance Sheets as of the date of purchase:


Current assets (including $36 million of cash acquired)	$	128
Property, plant and equipment, including nuclear fuel		129
Nuclear decommissioning trust funds		1,108
Deferred debits and other assets		31
Current liabilities		(174	)
Asset retirement obligation		(487	)
Deferred credits and other liabilities		(106	)
Long-term debt		(41	)

Total equity	$	588

As of December 31, 2003, the assets and liabilities of AmerGen were fully consolidated into Generation’s financial statements. This allocation of purchase price is preliminary related to the valuation of long-lived assets which will be finalized in early 2004.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

Exelon New England Holdings Asset Acquisition

On November 1, 2002, Generation purchased the assets of Sithe New England Holdings, LLC (now known as Exelon New England), a subsidiary of Sithe, and related power marketing operations. The total capacity of Exelon New England, including 2,421 MWs of gas-fired facilities under construction, was 4,066 MWs. The purchase price for the Exelon New England assets consisted of a $536 million note to Sithe, $14 million of direct acquisition costs and a $208 million adjustment to Generation’s previously existing investment in Sithe related to Exelon New England.

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


Current assets (including $12 million of cash acquired)	$	85
Property, plant and equipment		1,949
Deferred debits and other assets		63
Current liabilities		(154	)
Deferred credits and other liabilities		(149	)
Long-term debt		(1,036	)

Total purchase price	$	758

In connection with the acquisition, Generation assumed certain Sithe guarantees, including a guarantee of a contingent equity contribution to be made to Boston Generating. Exelon New England made a contribution of $38 million in full satisfaction of that contingent equity contribution guarantee in December 2003.

Boston Generating has a $1.25 billion credit facility (Boston Generating Facility), which was entered into primarily to finance the development and construction of the generating projects known as Mystic 8 and 9 and Fore River. Approximately $1.0 billion of debt was outstanding under the Boston Generating Facility at December 31, 2003, all of which is reflected in Generation’s Consolidated Balance Sheets as a current liability due to certain events of default described below. The Boston Generating Facility is non-recourse to Generation and an event of default under the Boston Generating Facility does not constitute an event of default under any other debt instruments of Generation or its subsidiaries.

The Boston Generating Facility required that all of the projects achieve “Project Completion,” as defined in the Boston Generating Facility (Project Completion), by July 12, 2003. Project Completion was not achieved by July 12, 2003, resulting in an event of default under the Boston Generating Facility. Mystic 8 and 9 and Fore River have begun commercial operation, although they have not yet achieved Project Completion.

As a result of Generation’s continuing evaluation of the projects and discussions with the lenders, Generation has commenced the process of an orderly transition out of the ownership of Boston Generating and the projects. In connection with the decision to transition out of the ownership of Boston Generating and the projects, Generation recorded an impairment charge of its long-lived assets pursuant to SFAS No. 144 of $945 million ($573 million net of income taxes) in operating expenses within the Consolidated Statements of Income and Comprehensive Income during the third quarter of 2003. In determining the amount of the impairment charge, management compared the carrying value of Boston Generating’s long-lived assets to the fair value of those assets. The fair value of Boston Generating’s long-lived assets was determined using the estimated future discounted cash flows from those assets. Forecasted cash flows incorporated assumptions relative to the period of time that Generation will continue to own and operate Boston Generating.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

Acquisition of Generating Plants from TXU

On April 25, 2002, Generation acquired two natural-gas generating 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 is obligated to make fixed capacity payments and variable expense payments, and to provide fuel to Generation in return for exclusive rights to the energy and capacity of the generation plants. Substantially the entire purchase price was allocated to property, plant and equipment.

Assets and Liabilities Held for Sale

Generation classified three gas turbines with a book value of $36 million as held for sale as of December 31, 2003 in anticipation of their sale in 2004. These turbines had been classified as other long-term assets as they were not placed into service.

3. Sithe

Generation is a 50% owner of Sithe and accounts for the investment as an unconsolidated equity investment. In 2003, Generation recorded impairment charges of $255 million (before income taxes) in other income and deductions within the Consolidated Statements of Income associated with a decline in the fair value of the Sithe investment, which was considered to be other-than-temporary. Generation’s management considered various factors in the decision to impair this investment, including management’s negotiations to sell its interest in Sithe. The discussions surrounding the sale indicated that the fair value of the Sithe investment was below its book value and, as such, impairment charges were required.

On November 25, 2003, Generation, Reservoir Capital Group (Reservoir) and Sithe completed a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe. The series of transactions is described below. Immediately prior to these transactions, Sithe was owned 49.9% by Generation, 35.2% by Apollo Energy, LLC (Apollo), and 14.9% by subsidiaries of Marubeni Corporation (Marubeni).

On November 25, 2003, entities controlled by Reservoir purchased certain Sithe entities holding six U.S. generating facilities, each a qualifying facility under the Public Utility Regulatory Policies Act, in exchange for $37 million ($21 million in cash and a $16 million two-year note); and entities controlled by Marubeni purchased all of Sithe’s entities and facilities outside of North America (other than Sithe Energies Australia (SEA) of which it purchased a 49% interest on November 24, 2003 for separate consideration) for $178 million. Marubeni agreed to acquire the remaining 51% of SEA in 90 days if a buyer is not found, although discussions regarding an extension are ongoing.

Following the sales of the above entities, Generation transferred its wholly owned subsidiary that held the Sithe investment to a newly formed holding company. The subsidiary holding the Sithe investment acquired the remaining Sithe interests from Apollo and Marubeni for $612 million using proceeds from a $580 million bridge financing and available cash. Generation sold a 50% interest in the newly formed holding company for $76 million to an entity controlled by Reservoir on November 25, 2003. On November 26, 2003, Sithe distributed $580 million of available cash to its parent, which then utilized the distributed funds to repay the bridge financing.

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

Guarantees, Including Indirect Guarantees of Indebtedness to Others” (FIN No. 45). These guarantees were issued to protect Reservoir from credit exposure of certain counter-parties through 2015 and other indemnities. In determining the value of the FIN 45 guarantees, Generation utilized probabilistic models to assess the possibilities of future payments under the guarantees.

At December 31, 2003, Sithe had total assets of $1.5 billion (including the $90 million note from Generation) and total liabilities of $1.6 billion. Of the total liabilities, Sithe had $1.0 billion of debt, which included $588 million of subsidiary debt incurred in prior years primarily to finance the construction of six generating facilities, $419 million of subordinated debt, $43 million of current portion of long-term debt, but excludes $469 million of non-recourse debt associated with Sithe’s equity investments. For the year ended December 31, 2003, Sithe had revenues of $690 million and incurred a net loss of approximately $72 million. The book value of Generation’s investment in Sithe was $47 million at December 31, 2003. Generation recorded $2 million of equity method income for its investment in Sithe during the twelve months ended December 31, 2003. See Note 1 – Significant Accounting Policies and Changes in Accounting Estimates for a discussion of Sithe in relation to FIN No. 46-R.

4. Property, Plant and Equipment

A summary of property, plant and equipment by classification as of December 31, 2003 and 2002 is as follows:


Asset Category	2003		2002
Electric-generation	$	7,976	$	5,678
Nuclear fuel		2,568		3,112
Construction work in progress		362		2,179
Other property, plant and equipment		225		52

Total property, plant and equipment		11,131		11,021
Less accumulated depreciation (including accumulated amortization of nuclear fuel of $1,596 and $2,212 as of December 31, 2003 and 2002, respectively)		4,025		6,323

Property, plant and equipment, net	$	7,106	$	4,698

In April 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. In July 2001, the estimated service lives were extended by 20 years for the remainder of Exelon’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 the plants. The service life extensions are subject to Nuclear Regulatory Commission (NRC) approval of NRC operating licenses, which are generally 40 years. The annualized reduction in depreciation expense from the change is $132 million.

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5. Jointly Owned Facilities—Property, Plant and Equipment

Generation’s ownership interest in jointly owned generation plants as of December 31, 2003 and 2002 were as follows:


December 31, 2003	Production Plant
December 31, 2003	Peach Bottom			Salem			Keystone			Conemaugh			Quad Cities
Operator		Generation			PSE&G			Reliant			Reliant			Generation
Ownership interest		50	%		42.59	%		20.99	%		20.72	%		75	%
Generation’s share:
Plant	$	449		$	106		$	167		$	210		$	193
Accumulated depreciation		239			24			106			138			18
Construction work in progress		1			48			2			1			24

December 31, 2002	Production Plant
December 31, 2002	Peach Bottom			Salem			Keystone			Conemaugh			Quad Cities
Operator		Generation			PSE&G			Reliant			Reliant			Generation
Ownership interest		50	%		42.59	%		20.99	%		20.72	%		75	%
Generation’s share:
Plant	$	417		$	44		$	131		$	214		$	171
Accumulated depreciation		229			12			98			127			4
Construction work in progress		52			36			28			1			35

Generation’s undivided ownership interests are financed with Generation funds and 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 Statements of Income.

6. Severance Accounting

Exelon provides severance and health and welfare benefits to terminated employees pursuant to pre-existing severance plans primarily based upon each individual employee’s years of service with Generation and compensation level. Generation accounts for its ongoing severance plans in accordance with SFAS No. 112, “Employer’s Accounting for Postemployment Benefits, an amendment of FASB Statements No. 5 and 43” (SFAS No. 112) and SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” and accrue amounts associated with severance benefits that are considered probable and that can be reasonably estimated.

As part of the implementation of Exelon’s new business model referred to as The Exelon Way, during 2003, Generation identified 470 positions, including professional, managerial and union employees, for elimination by the end of 2004. Generation recorded a charge for salary continuance severance of $33 million during 2003, which represented salary continuance severance costs related to The Exelon Way that were probable and could be reasonably estimated as of December 31, 2003. During 2003, Generation recorded an additional charge of $12 million associated with special health and welfare severance benefits offered through The Exelon Way. In addition to cash and health and welfare severance benefits, Generation incurred curtailment costs associated with pension and postretirement benefit plans of $15 million as a result of personnel reductions due to The Exelon Way. These amounts are net of $11 million in charges associated with The Exelon Way initiatives billed to co-owners of generating facilities. In total, Generation recorded charges of $60 million in 2003, net of co-owner

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

billings related to The Exelon Way. See Note 11 - Retirement Benefits for a description of the curtailment charges for the pension and postretirement benefit plans.

Generation based its estimate of the number of positions to be eliminated on management’s current plans and its ability to determine the appropriate staffing levels to effectively operate the business. Generation may incur further severance costs associated with The Exelon Way if additional positions are identified for elimination. These costs will be recorded in the period in which the costs can be reasonably estimated.

The following table details Generation’s total salary continuance severance expense recorded as an operating and maintenance expense within the Consolidated Statements of Income.


Salary continuance severance charges
Expense recorded – 2003 (a)	$	38
Expense recorded – 2002 (b)		2
Expense recorded – 2001 (b)		4

(a)	Severance expense in 2003 reflects severance costs associated with The Exelon Way and other severance costs incurred in the normal course of business.

(b)	Severance expense in 2002 and 2001 generally represents severance activity associated with the Merger and in the normal course of business.

The following table provides a roll forward of Generation’s salary continuance severance obligation from January 1, 2002 through December 31, 2003. The salary continuance severance obligation as of January 1, 2002 and amounts paid in 2002 relate to severance associated with the Merger.


Salary continuance severance obligation
Balance as of January 1, 2002	$	38
Severance charges recorded		2
Cash payments		(22	)
Other adjustments		(7	)

Balance as of January 1, 2003		11
Severance charges recorded		38
Cash payments		(9	)
Liability acquired upon consolidation of AmerGen		3

Balance as of December 31, 2003	$	43

7. Credit Facilities

Credit Facility

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

approximately $170 million of unused bank commitments under the credit agreements at December 31, 2003. Generation did not have any commercial paper outstanding at December 31, 2003 and 2002. Interest rates on the advances under the credit facility are based on either the London Interbank Offering Rate (LIBOR) or prime plus an adder based on the credit rating of the borrower as well as the total outstanding amounts under the agreement at the time of borrowing. The maximum adder would be 175 basis points.

Boston Generating Facility

Approximately $1.0 billion of debt was outstanding under the Boston Generating Facility at December 31, 2003, all of which was reflected in Generation’s Consolidated Balance Sheets as a current liability due to certain events of default described in Note 2 – Acquisitions and Dispositions. The Boston Generating Facility is non-recourse to Generation and an event of default under the Boston Generating Facility does not constitute an event of default under any other debt instruments of Generation or its subsidiaries.

Revolving Credit Facility

On September 29, 2003, Generation closed on an $850 million revolving credit facility that replaced a $550 million revolving credit facility that had originally closed on June 13, 2003. Generation used the facility to make the first payment to Sithe relating to the $536 million note that was used to purchase Exelon New England. This note was restructured in June 2003 to provide for a payment of $210 million of the principal on June 16, 2003, payment of $236 million of the principal on the earlier of December 1, 2003 or a change of control of Generation, and payment of the remaining principal on the earlier of December 1, 2004, certain liquidity needs, or a change of control of Generation. Generation paid $446 million on the note to Sithe in 2003. Generation terminated the $850 million revolving credit facility on December 22, 2003.

8. Long-Term Debt

Long-term debt is comprised of the following:


	December 31, 2003			December 31,
	Rates		Maturity Date	2003			2002
Boston Generating Facility	6.60%	(a)	2007	$	1,037		$	1,036
Senior unsecured notes	5.35%-6.95%		2011-2014		1,200			700
Pollution control notes, floating rates	0.95%-1.15%		2016-2034		363			346
Notes payable and other	6.20%-7.83%		2004-2020		128			56

Total long-term debt (b)					2,728			2,138
Unamortized debt discount and premium, net					(11	)		(1	)
Due within one year					(1,068	)		(5	)

Long-term debt				$	1,649		$	2,132

(a)

The rate for the Boston Generating Facility is stated as an average rate. Under the terms of the Boston Generating Facility, Boston Generating is required to effectively fix the interest rate on 50% of the borrowings through its maturity in 2007. The Boston Generating Facility is subject to a variable rate based on the LIBOR rate plus a margin of 1.65% as of February 2003; however, through the required interest-rate swaps, Boston Generating effectively fixed the LIBOR component of the interest rate at 5.73% on 83% of the debt balance as of December 31, 2003. The balance outstanding on the Boston Generating Facility has

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

been classified as a current liability as of December 31, 2003 due to certain events of default.

(b)	Long-term debt maturities in the periods 2004 through 2008 and thereafter are as follows:


2004	$	1,068
2005		12
2006		11
2007		10
2008		10
Thereafter		1,617

Total	$	2,728

During 2003, the following long-term debt was issued:


Type	Amount		Rate		Maturity
Pollution Control Revenue Bonds	$	17	Variable		June 1, 2027
Senior Notes	$	500	5.35	%	January 15, 2014

See Note 12 – Fair Value of Financial Assets and Liabilities for additional information regarding interest-rate swaps.

9. Income Taxes

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


	For the Year Ended December 31,
	2003			2002			2001
Included in operations:
Federal
Current	$	74		$	67		$	253
Deferred		(220	)		123			15
Investment tax credit		(8	)		(8	)		(8	)
State
Current		(4	)		18			51
Deferred		(21	)		17			16

	$	(179	)	$	217		$	327

Included in cumulative effects of changes in accounting principles:
Federal
Deferred	$	58		$	7		$	6
State
Deferred		12			2			1

	$	70		$	9		$	7

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

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


	For the Year Ended December 31,
	2003		2002		2001
U.S. Federal statutory rate	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
State income taxes, net of federal income tax benefit	3.9		3.7		5.2
Tax-exempt interest	1.8		(2.3	)	—
Nuclear decommissioning trust income	(2.1	)	0.9		(0.6	)
Amortization of investment tax credit	1.2		(0.9	)	(0.6	)
Deferred expense/revenue option adjustment	1.6		—		—
Other	1.2		(0.5	)	—

Effective income tax rate	42.6	%	35.9	%	39.0	%

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


	December 31,
	2003			2002
Deferred tax assets:
Decommissioning and decontamination obligations	$	335		$	703
Deferred pension and postretirement obligations		170			151
Unrealized gains on derivative financial instruments		83			66
Excess of tax value over book value of impaired assets(a)		460			—
Other, net		80			151

Total deferred tax assets		1,128			1,071

Deferred tax liabilities:
Plant basis difference		(715	)		(654	)
Deferred investment tax credit		(218	)		(226	)
Decommissioning and decontamination obligations		(227	)		(96	)
Emission allowances		(40	)		(36	)
Severance obligations		—			(7	)

Total deferred tax liabilities		(1,200	)		(1,019	)

Deferred income taxes (net) on the Consolidated Balance Sheets	$	(72	)	$	52

(a)	Includes impairments related to Generation’s investment in Sithe and Boston Generating.

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.

In 2002, Generation received $11 million from Exelon related to Generation’s allocation of tax benefits under Exelon’s Tax Sharing Agreement. Generation received no allocation of tax benefits under Exelon’s tax sharing agreement in 2003.

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

10. Nuclear Decommissioning and Spent Fuel Storage

Nuclear Decommissioning

Generation has an obligation to decommission its nuclear power plants. Based on the extended license lives of the nuclear plants, expenditures are expected to occur primarily during the period 2029 through 2056. Exelon, through its regulated subsidiary utility companies, ComEd and PECO, currently recovers costs for decommissioning its nuclear generating stations, excluding the AmerGen stations, through regulated rates. The amounts recovered from customers are deposited in trust accounts and invested for funding the future decommissioning costs of nuclear generating stations.

Generation had decommissioning assets in trust accounts of $4,721 million and $3,053 million as of December 31, 2003 and 2002, respectively, included as nuclear decommissioning trust funds on Generation’s Consolidated Balance Sheets. Generation anticipates that all trust fund assets will ultimately be used to decommission Generation’s nuclear plants.

SFAS No. 143 provides accounting requirements for retirement obligations (whether statutory, contractual or as a result of principles of promissory estoppel) associated with tangible long-lived assets. Generation adopted SFAS No. 143 as of January 1, 2003. After considering interpretations of the transitional guidance included in SFAS No. 143, Generation recorded income of $108 million (net of income taxes) as a cumulative effect of a change in accounting principle in connection with its adoption of this standard in the first quarter of 2003. The cumulative effect of a change in accounting principle included $28 million (net of income taxes of $18 million) associated with Generation’s investments in AmerGen and Sithe.

See Note 1 – Significant Accounting Policies for net income for 2002 and 2001, adjusted as if SFAS No. 143 had been applied effective January 1, 2001.

The asset retirement obligation (ARO) as of January 1, 2003 was determined under SFAS No. 143 to be $2,363 million. The following table provides a reconciliation of the previously recorded liabilities for nuclear decommissioning to the ARO reflected on Generation’s Consolidated Balance Sheets at December 31, 2003 and 2002:


Accumulated depreciation	$	2,845
Nuclear decommissioning liability for retired units		1,293

Decommissioning obligation at December 31, 2002		4,138
Net reduction due to adoption of SFAS No. 143		1,775

Asset retirement obligation at January 1, 2003		2,363
Consolidation of AmerGen effective December 22, 2003		487
Accretion expense for the year ended December 31, 2003		160
Expenditures on currently retired units		(14	)

Asset retirement obligation at December 31, 2003	$	2,996

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

Determination of Asset Retirement Obligation

In accordance with SFAS No. 143, a probability-weighted, discounted cash flow model with multiple scenarios was used to determine the “fair value” of the decommissioning obligation. SFAS No. 143 also stipulates that fair value represents the amount a third party would receive for assuming an entity’s entire obligation.

The present value of future estimated cash flows was calculated using credit-adjusted, risk-free rates applicable to the various businesses in order to determine the fair value of the decommissioning obligation at the time of adoption of SFAS No. 143.

Significant changes in the assumptions underlying the items discussed above could materially affect the balance sheet amounts and future costs related to decommissioning recorded in the consolidated financial statements.

Effect of Adopting SFAS No. 143

Generation was required to re-measure the decommissioning liabilities at fair value using the methodology prescribed by SFAS No. 143. The transition provisions of SFAS No. 143 required Generation to apply this re-measurement back to the historical periods in which AROs were incurred, resulting in a re-measurement of these obligations at the date the related assets were acquired. Since the nuclear plants previously owned by ComEd were acquired by Exelon on October 20, 2000 and subsequently transferred to Generation as a result of the Exelon corporate restructuring on January 1, 2001, Generation’s historical accounting for its ARO associated with those plants has been revised as if SFAS No. 143 had been in effect at the merger date.

In the case of the former ComEd plants, the calculation of the SFAS No. 143 ARO yielded decommissioning obligations lower than the value of the corresponding trust assets at January 1, 2003. ComEd has previously collected amounts from customers (which were subsequently transferred to Generation) in advance of Generation’s recognition of decommissioning expense under SFAS No. 143. While it is expected that the trust assets will ultimately be used entirely for the decommissioning of the plants, the current measurement required by SFAS No. 143 results in an excess of assets over related ARO liabilities. As such, in accordance with regulatory accounting practices and a December 2000 Illinois Interstate Commerce Commission Order issued to ComEd, amended February 2001 (ICC Order), a regulatory liability of $948 million was recorded at ComEd resulting from the intercompany payable established by Generation upon the adoption of SFAS No. 143. At December 31, 2003, the intercompany payable to ComEd, and likewise the regulatory liability at ComEd, totaled $1,183 million. Generation believes that all of the decommissioning assets, including up to $73 million of annual collections from ComEd ratepayers through 2006, will be used to decommission the former ComEd plants. Subsequent to 2006, there will be no further recoveries of decommissioning costs from customers of ComEd. Additionally, any surplus funds after the nuclear stations are decommissioned must be refunded to customers. Generation expects that its intercompany payable and ComEd’s regulatory liability will be reduced to zero at or before the conclusion of the decommissioning of the former ComEd plants.

In the case of the former PECO plants, the SFAS No. 143 ARO calculation yielded decommissioning obligations greater than the corresponding trust assets. As such, a regulatory asset of $20 million was recorded upon adoption at PECO resulting from the intercompany receivable established by Generation upon the adoption of SFAS No. 143. At December 31, 2003, the regulatory asset changed to a regulatory liability totaling $12 million as a result of decommissioning activity during the year. Generation believes that all of the decommissioning assets, including $29 million of annual collections from PECO ratepayers, which will increase

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

to approximately $33 million beginning in 2004, will be used to decommission the former PECO plants. Generation expects that its intercompany payable and PECO’s regulatory liability will be reduced to zero at the conclusion of the decommissioning of the former PECO plants.

At December 31, 2002, prior to the adoption of SFAS No. 143, Generation’s accumulated depreciation included $2,845 million for decommissioning liabilities related to active nuclear plants. This amount was reclassified to an ARO upon the adoption of SFAS No. 143. Generation also recorded an asset retirement cost (ARC) of $172 million related to the establishment of the ARO related to former PECO plants in accordance with SFAS No. 143. The ARC is being amortized over the remaining lives of the plants.

In accordance with the provisions of SFAS No. 143 and regulatory accounting guidance, Generation recorded a SFAS No. 143 transition adjustment to accumulated other comprehensive income to reclassify $168 million, net of tax, of accumulated net unrealized losses on the nuclear decommissioning trust funds to its intercompany payable to ComEd, and likewise to ComEd’s regulatory liability.

Accounting Methodology Under SFAS No. 143

Realized gains and losses and investment income on decommissioning trust funds for nuclear generating stations transferred to Generation from ComEd are reflected in other income and deductions in Generation’s Consolidated Statements of Income, while the unrealized gains and losses on marketable securities held in the trust funds adjust the intercompany payable to ComEd on Generation’s Consolidated Balance Sheets, with an equal adjustment to ComEd’s regulatory liability. The increases in the ARO are recorded in operating and maintenance expense as accretion expense. If the trust assets plus future collections permitted by the ICC Order are exceeded by the ARO, Generation is responsible for any shortfall in funding and at that point unrealized gains and losses will be recorded as other comprehensive income. The result of the above accounting has no earnings impact to Generation for as long as the trust assets exceed the ARO for the former ComEd plants.

The above accounting practices are also applicable for nuclear generating stations that were transferred to Generation from PECO as a result of the Exelon corporate restructuring on January 1, 2001. Additionally, depreciation expense is recognized on the ARC established upon the adoption of SFAS No. 143. However, as Generation has the expectation of full recovery from ratepayers of decommissioning costs of PECO’s former nuclear generating stations, the result of the above accounting has no earnings impact to Generation. Therefore, to the extent that the net of decommissioning revenues collected and realized gains and losses and investment income differs from the accretion expense to the ARO and the related depreciation of the ARC, an adjustment to net the amounts to zero is recorded by Generation as an adjustment to the intercompany payable to PECO, along with and adjustment to PECO’s regulatory liability balance.

The impact to Generation for the accounting for the decommissioning of the AmerGen plants was recorded within Generation’s equity in earnings of AmerGen prior to the acquisition of British Energy’s 50% interest in December 2003. In addition, Generation’s proportionate share of unrealized gains and losses on AmerGen’s decommissioning trust funds were reflected in Generation’s other comprehensive income.

Beginning in 2004, AmerGen’s decommissioning activity will be reflected in Generation’s Consolidated Statements of Income. Realized gains and losses and investment income on AmerGen’s decommissioning trust funds will be reflected in other income and deductions, while the unrealized gains and losses on marketable securities held in the trust funds will continue to be reflected in accumulated other comprehensive income. The increases in the ARO will be recorded in operating and maintenance expense as accretion expense. At December 31, 2003, trust fund assets available to decommission AmerGen plants totaled $1.1 billion while the ARO totaled $487 million.

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

Accounting Prior to the Adoption of SFAS No. 143

Prior to January 1, 2003, Generation accounted for the current period’s cost of decommissioning related to generating plants previously owned by PECO in accordance with common regulatory accounting practices by recording a charge to depreciation expense and a corresponding liability in accumulated depreciation concurrently with recognizing decommissioning collections. Financial activity of the decommissioning trust (e.g., investment income and realized and unrealized gains and losses on trust investments) was 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 would have, over time, established a corresponding liability in accumulated depreciation reflecting the cost to decommission the nuclear generating stations previously owned by PECO.

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. The difference between the decommissioning cost estimate and the decommissioning liability recorded in accumulated depreciation for the former ComEd operating stations was being amortized to depreciation expense on a straight-line basis over the remaining lives of the stations. The decommissioning cost estimate (adjusted annually to reflect inflation) for the former ComEd retired units recorded in deferred credits and other liabilities was 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) was reflected in nuclear decommissioning trust funds in Generation’s Consolidated Balance Sheets with a corresponding gain or expense recorded in Generation’s Consolidated Income Statements or in other comprehensive income. The offset to the financial activity in the decommissioning trust funds is summarized as follows:

•

Interest income was recorded in other income and deductions,

•

Realized gains and losses were recorded in other income and deductions,

•

Unrealized gains and losses were recorded in other comprehensive income, and

•

Trust fund operating expenses were recorded in operation and maintenance expense.

Spent Nuclear Fuel

Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy (DOE) is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel (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.

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

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. 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 June 10, 2003, the Court denied the Government’s summary judgment motions and set the case for trial on damages for November 2004. Also on June 10, 2003, the Court granted the Government’s motion to dismiss claims other than the breach of contract claims. Generation assumed the Standard Contract, as amended, in the 2001 corporate restructuring. Generation is now engaged in pre-trial document and deposition discovery on the damages claims.

In July 2000, PECO entered into an agreement (the Amendment) 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 the Amendment, 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 Amendment also provided 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 the 2001 corporate restructuring.

In November 2000, eight utilities with nuclear power plants filed a Joint Petition for Review against the DOE with the United States Court of Appeals for the Eleventh Circuit seeking to invalidate that portion of the Amendment 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 Amendment violates the NWPA and therefore is null and void. The Court did not hold that the Amendment 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 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. Pursuant to Article XVI(I), Generation has begun negotiations with the DOE and those negotiations are ongoing. Under the Amendment, Generation has received approximately $40 million in credits against contributions to the nuclear waste fund.

On August 14, 2003, Generation received a letter from the DOE demanding repayment of $40 million of previously received credits from the Nuclear Waste Fund. The letter also demanded $1.5 million of interest that was accrued as of that date and Generation has continued to record an interest expense each subsequent month. Although a new settlement would offset Generation’s payments, Generation nonetheless has reserved its 50% ownership share of these amounts. Because Generation expenses the dry storage casks and capitalizes the permanent components of its spent fuel storage facilities, these reserves increased Generation’s operating and maintenance expense approximately $11 million and its capital base approximately $9 million during 2003. The remainder of the recorded obligation to the DOE will be recovered from the co-owner of Peach Bottom.

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

with interest was $867 million. The liabilities for spent nuclear fuel disposal costs, including the one-time fee, were transferred to Generation as part of the corporate restructuring.

11. Retirement Benefits

Generation has adopted defined benefit pension plans and postretirement welfare benefit plans sponsored by Exelon. Substantially 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 Generation’s 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 14 of the Notes to Exelon’s Consolidated Financial Statements.

Approximately $75 million and $37 million were included in operating and maintenance expense in 2003 and 2002, respectively, for Generation’s allocated portion of Exelon’s pension and postretirement benefit expense. Generation contributed $145 million and $60 million to the Exelon-sponsored pension plans in 2003 and 2002 and did not contribute in 2001. Generation expects to contribute up to $170 million to the pension plans in 2004.

During 2003, Generation recognized curtailment charges of $18 million associated with an overall reduction in participants in its pension and postretirement benefit plans due to employee reductions associated with The Exelon Way.

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 $57 million, $31 million and $23 million for 2003, 2002 and 2001, respectively.

12. Fair Value of Financial Assets and Liabilities

Non-Derivative Financial Assets and Liabilities

Cash and cash equivalents, customer accounts receivable, trust accounts for decommissioning nuclear plants, vendor accounts payable and accrued liabilities are recorded at their fair value.

As of December 31, 2003 and 2002, Generation’s carrying amounts of cash and cash equivalents, accounts receivable, vendor accounts payable and accrued liabilities are representative of fair value because of the short-term nature of these instruments. Fair values of the trust accounts for decommissioning nuclear plants, long-term debt and preferred securities of subsidiaries are estimated based on quoted market prices for the same or similar issues.

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

The carrying amounts and fair values of Generation’s financial liabilities as of December 31, 2003 and 2002 were as follows:


	2003				2002
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Liabilities
Long-term debt (including amounts due within one year)	$	2,717	$	2,930	$	2,137	$	2,199

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. Concentrations of credit risk with respect to customer accounts receivable are limited due to Generation’s large number of customers.

Derivative Instruments

The fair values of Generation’s interest-rate swaps and power purchase and sale contracts are determined using quoted exchange prices, external dealer prices, or internal valuation models which utilize assumptions of future energy prices and available market pricing curves.

Generation enters into interest-rate swaps to hedge exposure to interest rate changes. Swaps related to variable-rate securities or forecasted transactions are accounted for as cash-flow hedges. The swaps are generally structured to mirror the terms of the hedged debt instruments; therefore, no material ineffectiveness has been recorded in earnings. The gain or loss in fair value of cash-flow hedges is recorded in other comprehensive income and will be recognized in earnings over the life of the hedged items. The gain or loss in fair value of fair-value hedges, along with the gain or loss on the hedged asset or liability that is attributable to the hedged risk, is recorded in earnings.

At December 31, 2003 and 2002, Generation had $861 million of notional amounts of interest-rate swaps outstanding with net deferred losses of $77 million and $92 million, respectively.

The notional amount of derivatives does not represent amounts that are exchanged by the parties and, thus, is not a measure of Generation’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.

During 2003, Generation settled forward-starting interest-rate swaps in an aggregate notional amount of $500 million and recorded a pre-tax gain of $1 million, which was recorded in other comprehensive income. The pre-tax gains on settlements of interest-rate swaps are being amortized over the life of the related debt to interest expense.

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. At December 31, 2003 and 2002, Generation had $216 million and $163 million, respectively, of energy derivatives recorded as net liabilities at fair value on its Consolidated Balance Sheets.

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

For the years ended December 31, 2003, 2002, and 2001 Generation recognized net unrealized losses of $16 million, and net unrealized gains of $6 million and $16 million, respectively, relating to mark-to-market activity of certain non-trading power purchase and sale contracts pursuant to SFAS No. 133. Mark-to-market activity on non-trading power purchase and sale contracts are reported in fuel and purchased power. For the years ended December 31, 2003, 2002 and 2001, Generation recognized net unrealized losses of $3 million and $9 million and net unrealized gains of $14 million, respectively, relating to mark-to-market activity on derivative instruments entered into for trading purposes. Gains and losses associated with financial trading are reported as revenue in the Consolidated Statements of Income. During 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.

As of December 31, 2003, $187 million of deferred net losses on derivative instruments in accumulated other comprehensive income are expected to be reclassified to earnings during the next twelve months. Amounts in accumulated other comprehensive income related to changes in interest-rate cash-flow hedges are reclassified into earnings when the forecasted interest payment occurs. Amounts in accumulated other comprehensive income related to changes in energy commodity cash-flow hedges 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 4 years.

Generation 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. Generation’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. 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.

Available-for-Sale Securities

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 as of December 31, 2003 and 2002.


	December 31, 2003
	Gross Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
Cash and cash equivalents (1)	$	72	$	—	$	—		$	72
Equity securities		2,402		300		(294	)		2,408
Debt securities
Government obligations		1,574		65		(4	)		1,635
Other debt securities		579		29		(2	)		606

Total debt securities		2,153		94		(6	)		2,241

Total available-for-sale securities	$	4,627	$	394	$	(300	)	$	4,721

(1)	Cash and cash equivalents do not include $12 million related to AmerGen’s nuclear decommissioning trust fund. AmerGen’s nuclear decommissioning trust fund cash and cash equivalents are classified elsewhere in the table.

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


	December 31, 2002
	Gross Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
Cash and cash equivalents	$	184	$	—	$	—		$	184
Equity securities		1,763		72		(482	)		1,353
Debt securities
Government obligations		938		62		—			1,000
Other debt securities		514		32		(30	)		516

Total debt securities		1,452		94		(30	)		1,516

Total available-for-sale securities	$	3,399	$	166	$	(512	)	$	3,053

Net unrealized gains of $94 million were recognized in noncurrent affiliate payables and other comprehensive income in Generation’s Consolidated Balance Sheets as of December 31, 2003. Net unrealized losses of $346 million were recognized in accumulated depreciation and other comprehensive income in Generation’s Consolidated Balance Sheets at December 31, 2002.


	For the Years Ended December 31,
	2003			2002			2001
Proceeds from sales	$	2,341		$	1,612		$	1,624
Gross realized gains		219			56			76
Gross realized losses		(235	)		(86	)		(189	)

Net realized losses of $16 million, $32 million and $127 million were recognized in other income and deductions in Generation’s Consolidated Statements of Income for the years ended December 31, 2003, 2002 and 2001, respectively. Additionally, net realized gains of $2 million and $14 million were recognized in accumulated depreciation and regulatory assets in Generation’s Consolidated Balance Sheets at December 31, 2002, and 2001, respectively. The fixed-income available-for-sale securities held at December 31, 2003 have an average maturity range of seven to nine years. The cost of these securities was determined on the basis of specific identification. See Note 10 – Nuclear Decommissioning and Spent Fuel Storage for further information regarding the nuclear decommissioning trusts.

The following table provides information regarding Generation’s available-for-sale securities in an unrealized loss position that are not other-than-temporarily impaired. The table shows the investments’ gross unrealized losses and fair value, aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position, at December 31, 2003.


	Less than 12 months				12 months or more				Total
	Unrealized losses		Fair value		Unrealized losses		Fair value		Unrealized losses		Fair value
Equity securities	$	33	$	231	$	261	$	775	$	294	$	1,006
Debt securities
Government obligations		4		232		—		11		4		243
Other debt securities		2		117		—		2		2		119

Total debt securities		6		349		—		13		6		362

Total temporarily impaired securities	$	39	$	580	$	261	$	788	$	300	$	1,368

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

As of December 31, 2003, Generation’s available-for-sale investments in unrealized loss positions that were not other-than-temporarily impaired were securities held in its nuclear decommissioning trust funds. These investments are held to fund Generation’s decommissioning obligation for its nuclear plants. Nuclear decommissioning activity occurs primarily after a plant is retired, and Generation estimates that decommissioning expenditures funded by the trust assets will begin in 2029.

Generation evaluates the historical performance, cost basis, and market value of its securities in unrealized loss positions in comparison to related market indices to assess whether or not the securities are permanently impaired. Generation concluded that the trending of the related market indices and historical performance of these securities over a long-term time horizon indicates that the securities are not other-than-temporarily impaired.

13. Commitments and Contingencies

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 rights for firm transmission.

At December 31, 2003, 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, LLC (Midwest Generation) contract, as expressed in the following tables:


	Net Capacity Purchases (1)		Power Only Sales		Power Only Purchases		Transmission Rights Purchases (2)
2004	$	716	$	3,393	$	1,661	$	113
2005		414		1,088		429		86
2006		410		290		276		3
2007		492		80		253		—
2008		434		—		226		—
Thereafter		3,880		—		723		—

Total	$	6,346	$	4,851	$	3,568	$	202

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

(1)

Generation will take 1,696 megawatts (MWs) of non-option coal capacity, 687 MWs of option coal capacity, 1,084 MWs of Collins Station capacity and 391 MWs of peaking capacity from Midwest Generation in 2004, the fifth and final year of the contract. In total, Generation has retained 3,858 MWs of capacity under the terms of the three existing PPAs with Midwest Generation. Net Capacity Purchases also include capacity sales to TXU under the purchase power agreement entered into in connection with the purchase of two generating plants in April 2002, which states that TXU will purchase the plant output from May through September from 2002 through 2006. During the periods covered by the power purchase agreement, TXU is obligated to make fixed capacity payments and variable expense payments and to provide fuel to Generation in return for exclusive rights to the energy and capacity of the generation plants. The combined capacity of the two plants is 2,334 MWs. Net capacity purchases also include tolling agreements that are accounted for as operating leases.

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

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. An extension of this contract for 2005 and 2006 has been agreed to by ComEd and Generation with substantially the same terms as the PPA currently in effect, except for the prices of energy which were reset to reflect the current rates at the time the extension was agreed to. This extension must still be filed with the ICC. Subsequent to 2006, ComEd will obtain all of its supply from market sources, which could include Generation. Additionally, 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.

Other Purchase Obligations

In addition to Generation’s energy commitments as described above, Generation has commitments to purchase fuel supplies for nuclear generation and various other purchase commitments related to the normal day-to-day operations of Generation’s business. As of December 31, 2003, these commitments were as follows:


			Expiration within
	Total		2004		2005-2006		2007-2008		2009 and beyond
Fuel purchase agreements (a)	$	3,034	$	476	$	825	$	582	$	1,151
Other purchase commitments (b)		54		19		22		13		—

(a)	Fuel Purchase Agreements – Commitments to purchase fuel supplies for nuclear and fossil generation.

(b)	Other Purchase Commitments – Commitments for spent fuel storage casks and other disposal services at nuclear generating facilities.

Two affiliates of Exelon New England have long-term supply agreements through December 2022 with Distrigas of Massachusetts, LLC (Distrigas) for gas supply, primarily for the Boston Generating units. Under the agreements, prices are indexed to New England gas markets. Exelon New England has guaranteed these entities’ financial obligations to Distrigas under the Distrigas agreements. It is currently anticipated that Exelon New England’s guaranty to Distrigas will continue following the eventual transfer of the ownership interests in Boston Generating. This guaranty is non-recourse to Generation. At December 31, 2003, Exelon New England had net assets of approximately $70 million, exclusive of the Boston Generating net assets.

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

Commercial Commitments

Generation’s commercial commitments as of December 31, 2003, representing commitments not recorded on the balance sheet but potentially triggered by future events, including obligations to make payment on behalf of other parties and financing arrangements to secure its obligations, are as follows:


			Expiration within
	Total		2004		2005-2006		2007-2008		2009 and beyond
Letters of credit (non-debt) (a)	$	85	$	85	$	—	$	—	$	—
Letters of credit (long-term debt) - interest coverage (b)		13		13		—		—		—
Performance guarantees (c)		201		—		—		—		201
Energy marketing contract guarantees (d)		53		53		—		—		—
Nuclear insurance premiums (e)		1,710		—		—		—		1,710

Total commercial commitments	$	2,062	$	151	$	—	$	—	$	1,911

(a)	Letters of credit (non-debt) – Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties. Guarantees of $66 million have been issued to provide support for certain letters of credit as required by third parties.

(b)

Letters of credit (long-term debt) - interest coverage – Reflects the interest coverage portion of letters of credit supporting floating-rate pollution control bonds. The principal amount of the floating-rate pollution control bonds of $363 million is reflected in long-term debt in Generation’s Consolidated Balance Sheet.

(c)	Performance guarantees – Guarantees issued to ensure execution under specific contracts.

(d)	Energy marketing contract guarantees – Guarantees issued to ensure performance under energy commodity contracts.

(e)

Nuclear insurance premiums – Represent the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site under the Secondary Financial Protection pool as required under the Price-Anderson Act. Exelon guarantees Generation’s potential obligation for nuclear insurance premiums.

Additionally, Generation could be required to guarantee up to an additional $42 million related to various construction and tax obligations associated with the Boston Generating facilities.

See Note 3 - Sithe for additional information about Generation’s unconsolidated equity investment.

Capital Expenditures

Generation’s estimated capital expenditures for 2004 are as follows:


(in millions)
Production plant (a)	$	573
Nuclear fuel		399

Total	$	972

(a)	Capital expenditures for production include expenditures to increase capacity of existing plants.

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

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, 2004, the current limit is $10.9 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance (currently $300 million for each operating site) and the remaining $10.6 billion is provided through mandatory participation in a financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed a maximum charge per reactor per incident. Effective August 20, 2003, the maximum assessment for all nuclear operators per reactor per incident (including a 5% surcharge) increased from $89 million to $101 million, payable at no more than $10 million per reactor per incident per year. This assessment is subject to inflation and state premium taxes. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims. The Price-Anderson Act expired on August 1, 2002 and was subsequently extended to the end of 2003 by the U.S. Congress. Only facilities applying for NRC licenses subsequent to the expiration of the Price-Anderson Act are affected. Existing commercial generating facilities, such as those owned and operated by Generation, remain subject to the provisions of the Price-Anderson Act and are unaffected by its expiration.

Additionally, NEIL 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. Including the AmerGen sites, Generation’s maximum share of any assessment is $61 million per year. Recovery under this insurance for terrorist acts is subject to the $3.2 billion aggregate limit and secondary to the property insurance described above. This limit would also not apply in cases of certified acts of terrorism under the Terrorism Risk Insurance Act as described above.

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

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.

Environmental Issues

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, 2003, Generation had accrued $10 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, 2003 were:


2004	$	21
2005		27
2006		26
2007		26
2008		26
Thereafter		438

Total minimum future lease payments (a)	$	564

(a)	Generation’s tolling agreements are accounted for as operating leases and are reflected as net capacity purchases in the energy commitments table above.

Rental expense under operating leases totaled $24 million, $25 million, and $29 million for the years ended December 31, 2003, 2002 and 2001, 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. Several of these actions resulted in nominal jury verdicts or were settled or dismissed. One action resulted in an award for the plaintiffs for a more substantial amount, but was reversed on April 22, 2003 by the Tenth Circuit Court of Appeals and remanded for retrial. An appeal by the plaintiffs to the United States Supreme Court was denied on November 10, 2003. No date has been set for a new trial.

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

The U.S. 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.

Raytheon and Mitsubishi Litigation. In May 2002, Raytheon Corporation (Raytheon) filed an arbitration against Sithe Fore River Development, LLC (now Fore River Development, LLC) in the International Chamber of Commerce Court of Arbitration (Arbitration Court). Raytheon is seeking equitable relief and damages totaling over $45 million for alleged owner-caused performance delays and force majuere events 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. Hearings by the Arbitration Court with respect to liability were held in January and February 2003. On May 12, 2003, the Arbitration Court issued an interim order finding in favor of Raytheon on liability, but limited the grounds upon which Raytheon could claim schedule and cost relief. The Arbitration Court ordered the parties to proceed to a damages phase to determine what, if any, damages Raytheon may recover. Hearings by the Arbitration Court with respect to damages were conducted in June and July 2003 and a final decision is expected in the first quarter of 2004.

In a related proceeding, on October 2, 2003, Mitsubishi Heavy Industries, LTD (MHI) and Mitsubishi Heavy Industries of America (MHIA) filed an action in the New York Supreme Court against Fore River Development, LLC and Mystic Development, LLC (collectively, the Project Companies) seeking to enjoin these indirect subsidiaries of Generation from drawing upon letters of credit posted to guarantee MHI’s performance under certain gas turbine contracts. MHI and MHIA also sought $34 million from these entities in connection with work performed on these contracts. The Project Companies filed a third-party complaint against Raytheon, claiming that Raytheon was responsible for the MHI and MHIA contracts.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

Clean Air Act.On June 1, 2001, the EPA issued to a subsidiary of the Company a Notice of Violation (NOV) and Reporting Requirement pursuant to Sections 113 and 114 of the Clean Air Act. The NOV alleges numerous exceedances of opacity limits and violations of opacity-related monitoring, recording and reporting requirements at Mystic Station in Everett, Massachusetts. On January 8, 2002, the EPA indicated that it had decided to resolve the NOV through an administrative compliance order and a judicial civil penalty action. In March 2002, the EPA issued and Mystic I, LLC, doing business as Mystic Generating (formerly known as Exelon Mystic Generating, LLC) (Mystic), a wholly owned subsidiary of the Company, voluntarily entered a Compliance Order and Reporting Requirement (Order) regarding Mystic Station. Under the Order, Mystic Station installed new ignition equipment on three of the four units at the plant. Mystic Station also undertook an extensive opacity monitoring and testing program for all four units at the plant to help determine if additional compliance measures are needed. Pursuant to the requirements of the Order, the subsidiary switched three of the four units to a lower sulfur fuel oil by September 1, 2002. The Order did not address civil penalties. By letter dated April 21, 2003, the United States Department of Justice notified the subsidiary that, at the request of the EPA, it intended to bring a civil penalty action, but also offered the opportunity to resolve the matter through settlement discussions. Mystic has entered into a consent decree with the EPA and the Department of Justice, the net discounted cost of which is approximately $4 million. The consent decree is subject to the approval of the United States District Court of the District of Massachusetts.

Real Estate Tax Appeals. Generation is challenging real estate taxes assessed on nuclear plants since 1997. Generation is involved in real estate tax appeals for 2000 through 2003, regarding the valuation of its Limerick and Peach Bottom plants, its Quad Cities Station (Rock Island County, IL) and, through AmerGen, Three Mile Island Nuclear Station (Dauphin County, PA).

During 2003, upon completion of updated nuclear plant appraisal studies, Generation recorded reductions of $15 million to reserves recorded for exposures associated with the real estate taxes. While Generation believes the resulting reserve balances as of December 31, 2003 reflect the most likely probable expected outcome of the litigation and appeals proceedings in accordance with SFAS No. 5, “Accounting for Contingencies,” the ultimate outcome of such matters could result in additional unfavorable or favorable adjustments to the consolidated financial statements of Generation, and such adjustments could be material.

General. Generation is involved in various other litigation matters that are being defended and handled in the ordinary course of business, and Generation maintains accruals for such costs that are probable of being incurred and subject to reasonable estimation. The ultimate outcome of such matters, as well as the matters discussed above, while uncertain, is not expected to have a material adverse effect on its financial condition or results of operations.

Capital Commitments

Generation has a 74% 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 $51 million

238

Exelon Generation Company, LLC and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

over the next 20 years to the party, which is not affiliated with Generation, that owns the remaining 26% interest. This amount reflects a return of that party’s investment in Southeast Chicago. 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 26% interest in Southeast Chicago. Additionally, Generation may be required to purchase the remaining 26% interest upon the occurrence of certain events, including Generation’s failure to maintain an investment grade rating. In conjunction with the adoption of SFAS No. 150 on July 1, 2003, Generation reclassified the minority interest associated with Southeast Chicago to a long-term liability. The total minority interest related to Southeast Chicago was $51 million as of December 31, 2003. Prior periods were not restated.

Credit Contingencies

Dynegy.Generation is a counterparty to 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, 2003, Generation has credit risk associated with Dynegy through Generation’s equity investment in Sithe. Sithe is a 60% owner of the Independence generating station, a 1,028-MW gas-fired facility that has an energy-only long-term tolling agreement with Dynegy, with a related financial swap arrangement. Sithe has entered into a contract to purchase the remaining 40% interest of the Independence generating station. As of December 31, 2003, 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 were unable to fulfill the terms of this agreement, Sithe would be required to impair this financial swap asset. Generation estimates, as a 50% owner of Sithe, that the impairment would result in an after-tax reduction of equity earnings of approximately $5 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 the Independence plant. Depending upon the timing of Dynegy’s failure to fulfill its obligations and the outcome of any restructuring initiatives, Exelon could realize an after-tax charge of up to $30 million, net of a FIN No. 45 guarantee recorded in connection with Generation’s sale of 50% of Sithe to Reservoir. In the event of a sale of Exelon’s investment in Sithe to a third party, proceeds from the sale could be negatively affected by up to $74 million, which would represent an after-tax loss of up to $43 million. Additionally, the future economic value of AmerGen’s purchased power arrangement with Illinois Power, a subsidiary of Dynegy, could be affected by events related to Dynegy’s financial condition. On February 3, 2004, Dynegy announced an agreement to sell its subsidiary Illinois Power Company to a third party, which, upon closing of the transaction, would reduce Generation’s credit risk associated with Dynegy.

Fund Transfer Restrictions

Under applicable law, Generation can pay dividends only from undistributed or current earnings. At December 31, 2003 and 2002, Generation had undistributed earnings of $602 million and $924 million, respectively.

14. Supplemental Financial Information

Supplemental Income Statement Information


	For the Year Ended December 31,
	2003		2002		2001
Depreciation, amortization and accretion expense:
Property, plant and equipment (a)	$	199	$	146	$	145
Nuclear fuel (b)		387		374		393
Decommissioning (c)		197		120		144

Total depreciation, amortization and accretion expense	$	783	$	640	$	682

239

Exelon Generation Company, LLC and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

(a)	Includes amortization of capitalized software costs.

(b)	Included in operating and maintenance expense in the Consolidated Statements of Income.

(c)

Prior to the adoption of SFAS No. 143 on January 1, 2003 these amounts were recorded in depreciation expense. Upon adoption of SFAS No. 143, these amounts were recorded in operating and maintenance expense in Generation’s Consolidated Statements of Income. See Note 10 – Nuclear Decommissioning and Spent Fuel Storage for further discussion of the adoption of SFAS No. 143.


	For the Year Ended December 31,
	2003			2002			2001
Taxes other than income
Real estate	$	83		$	102		$	94
Payroll		39			46			38
Other		(2	)		16			17

Total	$	120		$	164		$	149

Equity in earnings of unconsolidated affiliates
AmerGen (prior to purchase on December 22, 2003)	$	47		$	64		$	69
Sithe		2			23			21

Total	$	49		$	87		$	90

Other, net
Investment income	$	94		$	85		$	(8	)
Impairment of investment in Sithe		(255	)		—			—
Other income (expense)		(26	)		(8	)		(12	)

Total	$	(187	)	$	77		$	(20	)

Supplemental Cash Flow Information


	For the Year Ended December 31,
	2003			2002			2001
Cash paid (received) during the year:
Interest (net of amount capitalized)	$	57		$	63		$	74
Income taxes (net of refunds)		(14	)		(37	)		335
Non-cash investing and financing activities:
Purchase accounting estimate adjustment	$	59		$	—		$	—
Note received in connection with the sale of Sithe to Reservoir		92			—			—
Capital lease obligations		—			52			—
Noncash (distribution) contribution (to) from member		(17	)		3			(163	)
Contribution of land from minority interest of consolidated subsidiary		—			12			—
Note issued to Sithe in the Sithe New England Acquisition		2			534			—

Supplemental Balance Sheet Information


	December 31,
	2003		2002
Investments
Investment in EXRES SHC, Inc. (a)	$	47	$	—
Investment in Sithe (a)		—		478
Investment in AmerGen (b)		—		160
Other		18		19

Total	$	65	$	657

240

Exelon Generation Company, LLC and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

(a)	On November 25, 2003, Generation, Reservoir and Sithe completed a series of transactions that resulted in Generation indirectly owning a 50% interest in Sithe through EXRES SHC, Inc. See Note 3 – Sithe for further information on these transactions.

(b)	On December 22, 2003, Generation purchased British Energy’s 50% interest in AmerGen. See Note 2- Acquisitions and Dispositions for further information.


	December 31,
	2003		2002
Accrued expenses
Taxes accrued	$	115	$	203
Other		319		279

Total	$	434	$	482

15. Related-Party Transactions

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


	For the Years Ended December 31,
	2003		2002		2001
Operating revenues from affiliates
ComEd (1)	$	2,479	$	2,559	$	2,656
PECO (1)		1,433		1,438		1,162
Exelon Energy Company (2)		213		247		284
Purchased power from affiliates
AmerGen (3)		382		273		57
ComEd (4)		38		37		27
PECO (4)		—		3		6
Exelon Energy Company (4)		9		18		91
O&M from affiliates
Sithe (5)		—		13		—
ComEd (4)		12		14		12
PECO (4)		10		9		6
BSC (17)		127		116		110
Interest expense from affiliates
Sithe (11)		9		2		—
Exelon (6)		1		5		23
Exelon intercompany money pool (6)		2		—		—
ComEd (9)		—		—		9
PECO (8)		—		—		6
Interest income from affiliates
AmerGen (10)		1		2		—
Sithe (18)		—		—		2
ComEd (12,13)		—		4		10
Services provided to affiliates
AmerGen (14)		111		70		80
Sithe (15)		—		1		—

241

Exelon Generation Company, LLC and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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


	December 31,
	2003		2002
Receivables from affiliates
ComEd (1,4,9)	$	171	$	339
ComEd decommissioning (16)		11		59
AmerGen (3,10)		—		39
PECO (1)		115		124
BSC (17)		3		14
Exelon Energy Company (2)		18		19
Sithe (5)		3		—
Other		8		—
Note receivable from affiliate
Note receivable from EXRES SHC, Inc. (20)		92		—
Long-term receivable from affiliate
ComEd decommissioning receivable (16)		22		218
Other		—		2
Payables to affiliates
Sithe (5)		—		7
Exelon (7)		1		3
Payables to affiliates (non-current)
ComEd decommissioning (19)		1,183		—
PECO decommissioning (19)		12		—
Notes payable to affiliates
Exelon (6)		115		329
Exelon intercompany money pool (6)		301		—
Sithe (11)		90		534

(1)	Effective January 1, 2001, Generation entered into PPAs with ComEd and PECO. See Note 13 - Commitments and Contingencies for further information on the PPAs.

(2)	Generation sells power to Exelon Energy Company.

(3)

Generation entered into PPAs dated December 18, 2001 and November 22, 1999 with AmerGen. Under the 2001 PPA, Generation agreed to purchase from AmerGen all the energy from Unit No. 1 at Three Mile Island Nuclear Station from January 1, 2002 through December 31, 2014. Under the 1999 PPA, Generation agreed to purchase from AmerGen all of the residual energy from Clinton Nuclear Power Station (Clinton), through December 31, 2002. Currently, the residual output is approximately 31% of the total output of Clinton. In accordance with the terms of the AmerGen partnership agreement, the 1999 PPA will be extended through the end of the AmerGen partnership agreement in 2006.

(4)	Generation purchases power from AmerGen under PPAs as discussed in the above section of this note. Additionally, Generation purchases power from PECO for Generation’s own use, buys back excess power from Exelon Energy Company and purchases transmission and ancillary services from ComEd.

(5)

Under a service agreement dated December 18, 2000, Sithe provides Generation certain fuel and project development services. Sithe is compensated for these services in the amount agreed to in the work order, but not less than the higher of fully allocated costs for performing such services or the market price. In December 2003, Sithe received letter of credit proceeds of $3 million, which Generation was billed on behalf of Sithe.

(6)	Represents the outstanding balance of amounts borrowed under the intercompany money pool, and other short-term obligations payable to Exelon.

(7)	In order to facilitate payment processing, Exelon processes certain invoice payments on behalf of Generation.

242

Exelon Generation Company, LLC and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

(8)	Generation paid interest to PECO in 2001 related to a loan.

(9)	In order to facilitate payment processing, ComEd processes certain invoice payments on behalf of Generation.

(10)

In February 2002, Generation entered into an agreement to loan AmerGen up to $75 million at an interest rate equal to the 1-month London Interbank Offering Rate plus 2.25%. In July 2002, the limit of the loan agreement was increased to $100 million and the maturity date was extended to July 1, 2003. The loan was paid in its entirety during 2003.

(11)

Under the terms of the agreement to acquire Exelon New England dated November 1, 2002, Generation issued a $534 million note due on June 18, 2003 to Sithe. In June 2003, the principal of the note was increased $2 million and the payment terms of the note were changed. Generation paid $210 million of principal in June 2003, $236 million in November 2003, and the balance of the note is to be paid on the earlier of December 1, 2004, certain Sithe liquidity requirements, or upon a change of control of Generation. The note bears interest at the rate equal to LIBOR plus 0.875%.

(12)	In consideration for the net assets transferred as a part of the corporate restructuring effective January 1, 2001, Generation had a note receivable from ComEd. This note was repaid in 2001.

(13)	Interest income for 2002 is related to unpaid ComEd PPA billings.

(14)

Under a service agreement dated March 1, 1999, Generation provides AmerGen with certain operation and support services to the nuclear facilities owned by AmerGen. This service agreement has an indefinite term and may be terminated by Generation or AmerGen with 90 days notice. Generation is compensated for these services at cost.

(15)	Under a service agreement dated December 18, 2000, Generation provides certain engineering and environmental services for fossil facilities owned by Sithe and for certain developmental projects. Generation is compensated for these services at cost.

(16)	Generation had a short-term and a long-term receivable from ComEd, primarily representing ComEd’s legal requirements to remit collections of nuclear decommissioning costs from customers to Generation resulting from the 2001 corporate restructuring.

(17)	Generation receives a variety of corporate support services from BSC, including legal, human resources, financial and information technology services. Such services are provided at cost, including applicable overhead. Some third party reimbursements due Generation are recovered through BSC.

(18)	In August 2001, Generation loaned Sithe $150 million. The note, which bore interest at the Eurodollar rate, plus 2.25%, was repaid in December 2001 with the proceeds of bank borrowings.

(19)	Generation has a long-term payable to ComEd and PECO as a result of the adoption of SFAS No. 143. See Note 10 – Nuclear Decommissioning and Spent Fuel Storage for further discussion of the adoption of SFAS No. 143.

(20)

In connection with a series of transactions in November 2003 that restructured the ownership of Sithe (see Note 3 – Sithe for additional information), Generation received a $92 million note receivable from EXRES SHC, Inc, which holds the common stock of Sithe. Generation owns 50% of EXRES SHC, Inc and accounts for its investment in EXRES SHC, Inc. as an equity investment.

243

Exelon Generation Company, LLC and Subsidiary Companies

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

16. 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
	2003		2002		2003			2002		2003			2002		2003			2002
Quarter ended:
March 31	$	1,879	$	1,461	$	94		$	89	$	(52	)	$	66	$	56		$	79
June 30		1,886		1,559		201			113		142			84		142			84
September 30		2,537		2,213		(706	)		187		(428	)		163		(428	)		163
December 31		1,833		1,626		217			121		97			74		97			74

17. Subsequent Events

Effective January 1, 2004, Exelon Enterprises transferred their ownership of Exelon Energy Company to Generation.

In January 2004, the counterparties to the interest-rate swap agreements with Boston Generating, which had effectively fixed the interest rate on $861 million of notional principal related to Boston Generating credit facility, terminated the interest-rate swaps. The total net value of these interest-rate swaps as of the respective termination dates is $82 million, which is a net payable to the counterparties.

243

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Exelon, ComEd, PECO and Generation

None.

ITEM 9A.

CONTROLS AND PROCEDURES

Exelon

During the fourth quarter of 2003, 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 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. Exelon does not control or manage certain of its unconsolidated entities and thus its access and ability to apply its disclosure controls and procedures to entities that it does not control or manage are more limited than is the case for the subsidiaries it controls and manages.

Accordingly, as of December 31, 2003, these officers (principal executive officer and principal financial officer) concluded that Exelon’s disclosure controls and procedures were effective to 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.

ComEd

During the fourth quarter of 2003, 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 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 procedures can only provide reasonable, not absolute, assurance that the above objectives have been met. ComEd does not control or manage certain of its unconsolidated entities and thus its access and ability to apply its disclosure controls and procedures to entities that it does not control or manage are more limited than is the case for the subsidiaries it controls and manages.

Accordingly, as of December 31, 2003, these officers (principal executive officer and principal financial officer) concluded that ComEd’s disclosure controls and procedures were effective to 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.

245

PECO

During the fourth quarter of 2003, 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 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. PECO does not control or manage certain of its unconsolidated entities and thus its access and ability to apply its disclosure controls and procedures to entities that it does not control or manage are more limited than is the case for the subsidiaries it controls and manages.

Accordingly, as of December 31, 2003, these officers (principal executive officer and principal financial officer) concluded that PECO’s disclosure controls and procedures were effective to 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.

Generation

During the fourth quarter of 2003, 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 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 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. Generation does not control or manage certain of its unconsolidated entities and thus its access and ability to apply its disclosure controls and procedures to entities that it does not control or manage are more limited than is the case for the subsidiaries it controls and manages.

Accordingly, as of December 31, 2003, these officers (principal executive officer and principal financial officer) concluded that Generation’s disclosure controls and procedures were effective to 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.

246

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” in Exelon’s definitive Proxy Statement (2004 Exelon Proxy Statement) to be filed with the SEC prior to April 29, 2004, 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 the Registrants at December 31, 2003.

Code of Ethics

Exelon’s Code of Business Conduct is the code of ethics that applies to Exelon’s Chief Executive Officer, Chief Financial Officer, Corporate Controller, and other finance organization employees. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Exelon’s website at www.exeloncorp.com. The Code of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Katherine K. Combs, Vice President and Corporate Secretary, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.

If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or Corporate Controller, Exelon will disclose the nature of such amendment or waiver on Exelon’s website, www.exeloncorp.com, or in a report on Form 8-K.

ComEd

The information required by Item 10 relating to executive officers is set forth above in ITEM 1. Business - Executive Officers of the Registrants at December 31, 2003.

Directors

John W. Rowe.Age 58. Chairman and CEO of Exelon Corporation since April 23, 2003; President and Co-CEO of Exelon since October 20, 2002. Director of ComEd since 1998. Former Chairman, President and CEO of Unicom Corporation and Commonwealth Edison Company. Former President and CEO of the New England Electric System. Other directorships: UnumProvident Corporation, The Northern Trust Company, and Sunoco, Inc.

Frank M. Clark. Age 58. Senior vice president of Exelon Corporation. President of ComEd since October 2001. Previously senior vice president, distribution, customer and market services and external affairs of ComEd. Other directorship: Waste Management, Inc.

Robert S. Shapard. Age 48. Executive vice president and chief financial officer of Exelon Corporation since October 21, 2002. Previously executive vice president and CFO of Covanta Energy Corporation during 2002. For 2000 through 2001, executive vice president and CFO of Ultramar Diamond Shamrock. Prior to that, chief executive officer of TXU Australia, LTD, a wholly owned subsidiary of TXU Corporation.

Oliver D. Kingsley, Jr. Age 61. President and Chief Operating Officer of Exelon since April 2003. 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.

247

Michael B. Bemis. Age 56. President, Exelon Energy Delivery. Prior to his election to his listed position, Mr. Bemis was Chief Executive Officer of Entergy’s London Electricity PLC; and Chairman and CEO of Master Graphics, Inc.

S. Gary Snodgrass. Age 52. Senior Vice President and Chief Human Resources Officer, Exelon. Prior to his election to his listed position, Mr. Snodgrass was Chief Administrative Officer of Exelon; Senior Vice President of ComEd and Unicom; Vice President of ComEd and Unicom; and Vice President of USG Corporation.

Code of Ethics

Exelon’s Code of Business Conduct is the code of ethics that applies to ComEd’s Chief Executive Officer, Chief Financial Officer, Corporate Controller, and other finance organization employees. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Exelon’s website atwww.exeloncorp.com. The Code of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Katherine K. Combs, Vice President and Corporate Secretary, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.

If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or Corporate Controller, ComEd will disclose the nature of such amendment or waiver on Exelon’s website,www.exeloncorp.com, or in a report on Form 8-K.

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 (2004 PECO Information Statement) to be filed with the SEC prior to April 29, 2004, 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 the Registrants at December 31, 2003. The information required by Item 10 relating to PECO’s code of ethics is incorporated herein by reference to the information labeled “CODE OF ETHICS” in the 2004 PECO Information Statement.

Generation

The information required by Item 10 relating to executive officers is set forth above in ITEM 1. Business - Executive Officers of the Registrants at December 31, 2003.

Directors

Generation operates as a limited liability company and has no Board of Directors.

Code of Ethics

Exelon’s Code of Business Conduct is the code of ethics that applies to Generation’s Chief Executive Officer, Chief Financial Officer, Corporate Controller, and other finance organization employees. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Exelon’s website atwww.exeloncorp.com. The Code of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Katherine K. Combs, Vice President and Corporate Secretary, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.

248

If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or Corporate Controller, Generation will disclose the nature of such amendment or waiver on Exelon’s website,www.exeloncorp.com, or in a report on Form 8-K.

ITEM 11.

EXECUTIVE COMPENSATION

Exelon

The information required by Item 11 is incorporated herein by reference to the information labeled “Executive Compensation” and “Board Compensation” in the 2004 Exelon Proxy 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 the paragraphs under the subheading “Compensation Committee Report on Executive Compensation”) in the 2004 PECO Information Statement.

ComEd and Generation

Board Compensation

Since the Merger Date, the board of directors of ComEd has been comprised solely of employees of ComEd, Exelon Corporation, or its subsidiaries. These individuals receive no additional compensation for serving as directors of ComEd.

Generation operates a limited liability company and has no Board of Directors.

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Executive Compensation

ComEd

Summary Compensation Table


								Long-Term Compensation					All other compensation
		Annual Compensation						Restricted stock awards (b)		Number of options awarded	Payouts
Name	Year	Salary		Bonus		Other (a)		Restricted stock awards (b)		Number of options awarded	Payouts
Michael B. Bemis (c)	2003 2002 2001	$	414,567 121,154 —	$	292,346 121,347 —	$	177,414 — —	$	423,020 — —	— — —	$	— — —	$	1,564,636 6,058 —	(d)

Pamela B. Strobel (e)	2003 2002 2001		500,673 474,923 450,000		403,374 470,400 500,500		— — —		634,530 520,905 378,187	36,000 60,000 —		— — —		25,034 23,746 23,605

John W. Rowe	2003 2002 2001		1,185,289 1,104,000 1,050,000		1,400,000 1,550,000 1,500,300		342,341 185,121 71,369		2,733,360 1,909,985 1,354,104	175,000 200,000 233,000		— — —		59,264 55,200 52,729

Oliver D. Kingsley, Jr.	2003 2002 2001		824,038 728,634 650,000		969,924 823,680 928,000		185,294 102,387 —		1,164,737 2,373,140 597,729	60,000 80,000 —		— — —		41,202 36,432 32,499

Robert S. Shapard (f)	2003 2002 2001		512,404 96,154 —		411,362 83,609 —		— 72,344 —		634,530 102,742 —	36,000 20,000 —		— — —		25,620 1,923 —

Frank M. Clark	2003 2002 2001		377,404 352,500 310,000		227,880 274,827 304,000		— — —		444,171 604,470 243,979	27,000 35,000 —		— — —		18,870 17,625 15,606

(a)

These amounts include perquisites and other benefits if the aggregate amount of such benefits exceeds $50,000. For Mr. Bemis, the amount shown for 2003 includes $121,147 for moving expenses and $36,456 for gross up payments. For Mr. Rowe, the amount shown for 2003 includes $269,435 for personal use of corporate aircraft, and $25,733 for gross-up payments. For Mr. Kingsley, the amount shown for 2003 includes $164,152 for personal use of corporate aircraft.

(b)	As of December 31, 2003 the officers named above held the following amounts of restricted shares:


	Number of restricted shares	Dollar value of restricted shares
Michael B. Bemis	6,500	$	431,430
Pamela B. Strobel	19,705		1,307,624
John W. Rowe	78,269		5,193,931
Oliver D. Kingsley, Jr.	59,843		3,971,181
Robert S. Shapard	26,177		1,737,106
Frank M. Clark	18,403		1,221,252

The number of shares above includes performance shares which were granted in January 2004 with respect to 2003 and are included in the Summary Compensation Table for 2003. One-third of the shares awarded vested immediately and one-third vests on each of the second and third anniversaries of the grant date. At the officer’s election, subject to meeting 125% of their stock ownership requirements, one-half of future vested performance shares may be settled in cash based on the fair market value of the stock at the time of vesting. Unvested shares continue to receive dividends. Shares are valued at the closing price of December 31, 2003: $66.36.

(c)	Mr. Bemis commenced employment on August 12, 2002.

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(d)

Mr. Bemis received a $100,000 sign on bonus when hired in August 2002, payable in January 2003. In connection with his resignation as of February 1, 2004, Mr. Bemis received a lump sum severance payment of $450,000 and a fully vested award of 15,000 shares, worth $1,004,700, representing final payment of his special incentive award program with respect to the Sithe transaction, and $9,936 to terminate an apartment lease.

(e)	Ms. Strobel was CEO through April 30, 2003.

(f)	Mr. Shapard commenced employment on October 21, 2002.

The table below shows the number and value of exercised and unexercised stock options for the named executive officers of ComEd during 2003. Value is determined using the market value of Exelon common stock at the December 31, 2003 price of $66.36 per share, less the value of Exelon common stock at the exercise price. All options whose exercise price exceeds the market value at the date of valuation are valued at zero.


Executive officer	Number of shares acquired by exercise	Dollar value realized from exercise		Number of securities underlying remaining options		Dollar value of in-the-money options
Executive officer	Number of shares acquired by exercise	Dollar value realized from exercise		Exercisable	Unexercisable	Exercisable		Unexercisable
Michael B. Bemis	—	$	—	—	—	$	—	$	—
Pamela B. Strobel	47,500		1,151,353	142,250	76,000		1,908,395		1,380,600
John W. Rowe	—		—	706,467	541,633		14,015,095		5,523,244
Oliver D. Kingsley, Jr.	57,000		1,411,320	287,917	113,333		4,600,461		2,041,794
Robert S. Shapard	—		—	6,667	49,333		115,739		834,461
Frank M. Clark	19,584		196,694	63,000	50,333		432,180		905,844

The following table presents options granted to the named executive officers of ComEd in 2003.


Executive officer	Number of securities underlying options granted	Percentage of total options granted to employees		Exercise or base price ($/share)	Options expiration date	Grant date present value (a)
Michael B. Bemis	—	0.00	%	—	—	$	—
Pamela B. Strobel	36,000	1.14	%	49.61	1/26/2013		397,800
John W. Rowe	175,000	5.52	%	49.61	1/26/2013		1,933,750
Oliver D. Kingsley, Jr.	60,000	1.89	%	49.61	1/26/2013		663,000
Robert S. Shapard	36,000	1.14	%	49.61	1/26/2013		397,800
Frank M. Clark	27,000	0.85	%	49.61	1/26/2013		298,350

(a)

The “grant date present values” are an estimate based on the Black-Scholes option pricing model. Although executives risk forfeiting these options in some circumstances, these risks are not factored into the calculated values. The actual value of these options will be determined by the excess of the stock price over the exercise price on the date that the options are exercised. There is no certainty that the actual value realized will be at or near the value estimated by the Black-Scholes option pricing model. The assumptions used for the Black-Scholes model are as of the date of the grants, January 27, 2003 and are as follows: Risk free interest rate: 3.04%; Volatility: 30.60%; Dividend Yield: 3.34%; Time of Exercise: 5 Years.

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Generation

Summary Compensation Table


								Long-Term Compensation					All other compensation
		Annual Compensation						Restricted Stock awards (b)		Number of options awarded	Payouts
Name	Year	Salary		Bonus		Other (a)		Restricted Stock awards (b)		Number of options awarded	Payouts
Oliver D. Kingsley, Jr.	2003 2002 2001	$	824,038 728,634 650,000	$	969,924 823,680 928,000	$	185,294 102,387 —	$	1,164,737 2,373,140 597,729	60,000 80,000 —	$	— — —	$	41,202 36,432 32,499

John W. Rowe	2003 2002 2001		1,185,289 1,104,000 1,050,000		1,400,000 1,550,000 1,500,300		342,341 185,121 71,369		2,733,360 1,909,985 1,354,104	175,000 200,000 233,000		— — —		59,264 55,200 52,729

John L. Skolds	2003 2002 2001		530,673 492,423 430,000		393,837 499,800 483,900		— — 59,772		634,530 416,724 353,750	40,000 45,000 —		— — —		26,534 24,621 21,499

Ian P. McLean	2003 2002 2001		411,827 385,462 362,311		273,607 187,176 323,100		— — 134,267		634,530 — 261,042	36,000 49,644 —		— 1,000,000 149,160		20,591 3,846 683

John F. Young (c)	2003 2002 2001		311,923 — —		214,159 — —		144,943 — —		371,086 — —	15,000 — —		— — —		159,635 — —

Robert S. Shapard (d)	2003 2002 2001		512,404 96,154 —		411,362 83,609 —		— 72,344 —		634,530 102,742 —	36,000 20,000 —		— — —		25,620 1,923 —

(a)

These amounts include perquisites and other benefits if the aggregate amount of such benefits exceeds $50,000. For Mr. Kingsley, the amount shown for 2003 includes $164,152 for personal use of corporate aircraft. For Mr. Rowe, the amount shown for 2003 includes $269,435 for personal use of corporate aircraft, and $25,733 for gross-up payments. For Mr. Young, the amount shown for 2003 includes $82,578 for moving expenses and $59,359 for gross up payments.

(b)	As of December 31, 2003 the officers named above held the following amounts of restricted shares:


	Number of restricted shares	Dollar value of restricted shares
Oliver D. Kingsley, Jr.	59,843	$	3,971,181
John W. Rowe	78,269		5,193,931
John L. Skolds	27,337		1,814,083
Ian McLean	13,626		904,221
John F. Young	8,202		544,285
Robert S. Shapard	26,177		1,737,106

(c)	Mr. Young commenced employment on March 3, 2003. Other compensation includes a $150,000 signing bonus.

(d)	Mr. Shapard commenced employment on October 21, 2002. He was an executive officer of Generation through September 9, 2003.

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The table below shows the number and value of exercised and unexercised stock options for the named executive officers of Generation during 2003. Value is determined using the market value of Exelon common stock at the December 31, 2003 price of $66.36 per share, less the value of Exelon common stock at the exercise price. All options whose exercise price exceeds the market value at the date of valuation are valued at zero.


Executive officer	Number of shares acquired by exercise	Dollar value realized from exercise		Number of securities underlying remaining options		Dollar value of in-the-money options
Executive officer	Number of shares acquired by exercise	Dollar value realized from exercise		Exercisable	Unexercisable	Exercisable		Unexercisable
Oliver D. Kingsley, Jr.	57,000	$	1,411,320	287,917	113,333	$	4,600,461	$	2,041,794
John W. Rowe	—		—	706,467	541,633		14,015,095		5,523,244
John L. Skolds	28,500		289,275	95,000	70,000		840,400		1,253,200
Ian P. McLean	135,000		2,491,374	89,548	69,096		1,413,216		1,237,872
John F. Young	—		—	—	15,000		—		256,500
Robert Shapard	—		—	6,667	49,333		115,739		834,461

The following table presents options granted to the named executive officers of Generation in 2003.


Executive officer	Number of securities underlying options granted	Percentage of total options granted to employees		Exercise or base price ($/share)	Options expiration date	Grant date present value (a)
Oliver D. Kingsley, Jr.	60,000	1.89	%	49.61	1/26/2013	$	663,000
John W. Rowe	175,000	5.52	%	49.61	1/26/2013		1,933,750
John L. Skolds	40,000	1.26	%	49.61	1/26/2013		442,000
Ian P. McLean	36,000	1.14	%	49.61	1/26/2013		397,800
John F. Young (b)	15,000	0.47	%	49.26	3/02/2013		148,200
Robert S. Shapard	36,000	1.14	%	49.61	1/26/2013		397,800

(a)

(b)	Commenced employment on March 3, 2003. The assumptions used for the Black-Scholes model are as of the date of the grant, March 3, 2003 and are as follows: Risk-free interest rate: 2.68%; Volatility: 28.30%; Dividend Yield: 3.34%; Time of Exercise: 5 years.

Retirement Benefit Plans

Exelon Retirement Benefits

The following tables show the estimated annual retirement benefits payable on a straight-life annuity basis to participating employees, including officers, in the earnings and year of service classes indicated, under Exelon’s non-contributory retirement plans applicable to ComEd and Generation.

Effective January 1, 2001, Exelon Corporation assumed sponsorship of the Commonwealth Edison Company Service Annuity System and the PECO Energy Company Service Annuity Plan. Effective December 31, 2001, these plans were merged to form the Exelon Corporation Retirement Program, which incorporates the separate benefit formula of each merged plan for employees in business units formerly covered by that merged plan. Effective January 1, 2001, Exelon Corporation also established two cash balance pension plans which cover management employees and electing bargaining unit employees hired on or after such date. The amounts shown in the table are not subject to any deduction for Social Security or other offset amounts.

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Covered Compensation

Covered compensation includes salary and bonus which is disclosed in the Summary Compensation Table for the named executive officers. The calculation of retirement benefits under the plans is based upon average earnings for the highest consecutive five-year period under the PECO Energy Company Service Annuity Benefit Formula and for the highest four-year period (three-year for certain represented employees) under the ComEd Service Annuity Benefit Formula.

The Internal Revenue Code limits the annual benefits that can be paid from a tax-qualified retirement plan to $170,000 as of January 1, 2001. As permitted by the Employee Retirement Income Security Act of 1974, Exelon sponsored supplemental plans which allow the payment out of its general assets of any benefits calculated under provisions of the applicable retirement plan which may be above these limits.

Credited Years of Service

The executive officers who are named in the Summary Compensation Tables have the following credited years of service as of December 31, 2003 (partial years are not included):


ComEd		Generation
Michael B. Bemis	—	Oliver D. Kingsley, Jr.	31 years
Pamela B. Strobel	19 years	John W. Rowe	25 years
John W. Rowe	25 years	John L. Skolds	3 years
Oliver D. Kingsley, Jr.	31 years	Ian P. McLean	4 years
Robert S. Shapard	1 year	John F. Young	1 year
Frank M. Clark	38 years	Robert S. Shapard	1 year

In addition, Mr. Skolds will receive an additional 7¹/2 years of service upon his 5th anniversary of employment and 7¹/2 years upon his 10th anniversary

Recognizing shareholder concern about executive compensation, Exelon agreed that after January 1, 2004, it would not grant additional unearned service credits for current executives in the ComEd and PECO pension plans without shareholder approval. It also agreed that it would not provide more than two years’ service credit under new change-in-control agreements without shareholder approval. If Exelon should need to offer new executives more than the pension benefits that they would give up to come to work for Exelon, the additional pension benefits would be performance-based and not guaranteed. The agreement does not affect benefits or compensation under existing agreements, arrangements or change-in-control provisions, and it does not limit Exelon’s rights to provide compensation or benefits outside the pension plans.

Service Annuity System Benefit Table – PECO


		Annual normal retirement benefits based on specified years of service and earnings
Highest 5-year annual earnings		10 years		15 years		20 years		25 years		30 years		35 years		40 years
$	100,000	$	19,119	$	26,179	$	33,239	$	40,299	$	47,358	$	54,418	$	61,478
	200,000		39,619		54,429		69,239		84,049		98,858		113,668		128,478
	300,000		60,119		82,679		105,239		127,799		150,358		172,918		195,478
	400,000		80,619		110,929		141,239		171,549		201,858		232,168		262,478
	500,000		101,119		139,179		177,239		215,299		253,358		291,418		329,478
	600,000		121,619		167,429		213,239		259,049		304,858		350,668		396,478
	700,000		142,119		195,679		249,239		302,799		356,358		409,918		463,478
	800,000		162,619		223,929		285,239		346,549		407,858		469,168		530,478
	900,000		183,119		252,179		321,239		390,299		459,358		528,418		597,478
	1,000,000		203,619		280,429		357,239		434,049		510,858		587,668		664,478

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Service Annuity System Benefit Table – ComEd


Highest 5-year annual earnings		Annual normal retirement benefits based on specified years of service and earnings
Highest 5-year annual earnings		10 years		15 years		20 years		25 years		30 years		35 years		40 years
$	100,000	$	17,783	$	29,472	$	40,282	$	50,414	$	60,031	$	69,261	$	78,200
	200,000		35,867		59,922		82,180		103,036		122,808		141,743		160,033
	300,000		53,951		90,371		124,078		155,659		185,584		214,223		241,865
	400,000		72,029		120,820		165,976		208,281		248,359		286,704		323,698
	500,000		90,118		151,269		207,874		260,903		311,136		359,185		405,531
	600,000		108,202		181,719		249,772		313,252		373,912		431,666		487,364
	700,000		126,285		212,168		291,670		366,147		436,687		504,148		569,196
	800,000		144,369		242,618		333,568		418,769		499,463		476,628		651,029
	900,000		162,453		273,067		375,466		471,391		562,240		649,109		732,862
	1,000,000		180,536		303,517		417,364		524,013		625,016		721,590		814,694

Cash Balance Pension Plan

Mr. Shapard participates in the Exelon Corporation Cash Balance Pension Plan. Under that plan, a notional account is established for each participant. For each active participant, the account balance grows as a result of annual benefit credits and annual investment credits.

Currently, the benefit credit under the plan is 5.75% of base pay and actual annual incentive award (subject to the Code Section 401(a)(17) compensation limit). The annual investment credit is the greater of 4% or the average for the year of the S&P 500 Stock Index and the applicable interest rate used under Code Section 417(e) to determine lump sums, determined as of November of such year. Although employees receive benefit credits only while they are active participants, investment credits are added to the account each year until benefits are distributed.

Benefits are vested and nonforfeitable after completion of at least five years of service, and are payable following termination of employment. Apart from the vesting requirement, and as described above, years of service are not relevant to a determination of accrued benefits under the Cash Balance Pension Plan.

Employment Agreements

Employment Agreement with John W. Rowe

Under the amended and restated employment agreement between Exelon and Mr. Rowe, Mr. Rowe has been serving as Chief Executive Officer of Exelon, Chairman of the Board and a member of the Exelon board of directors since the 2002 annual meeting of shareholders.

Under the employment agreement, which continues in effect until Mr. Rowe’s termination, Mr. Rowe’s annual base salary is determined by Exelon’s compensation committee. He is eligible to participate in the annual incentive award program, long-term incentive plan and all savings, deferred compensation, retirement and other employee benefit plans generally available to other senior executives of Exelon on the same basis as other senior executives of Exelon. His life insurance coverage will be at least three times his base salary.

In addition, Mr. Rowe is entitled to receive a special supplemental executive retirement plan (SERP) benefit upon termination of employment for any reason other than for cause. The special SERP benefit, when added to all other retirement benefits provided to Mr. Rowe by Exelon, will equal Mr. Rowe’s SERP benefit, calculated under the terms of the SERP in effect on March 10, 1998 as if:

•

he had attained age 60 (or his actual age, if greater),

•

he had earned 20 years of service on March 16, 1998 and one additional year of service on each anniversary after that date and prior to termination, and

255

•

his annual incentive awards for each of 1998 and 1999 had been $300,000 greater than the annual incentive awards he actually received for those years.

On February 19, 1999, Mr. Rowe was granted a right to receive, on termination of employment, 12,344 shares of Exelon common stock, increased by the number of shares that could have been acquired with dividends on such number of shares after that date and subject to adjustment for events such as recapitalization, merger, or stock splits.

Except as provided in the next paragraph, if Exelon terminates Mr. Rowe’s employment for reasons other than cause, death or disability or if he terminates employment for good reason, he would be entitled to the following benefits:

•

for the two-year severance period, continuation of life, disability, accident, health and other welfare benefits for him and his family, plus post-retirement health care coverage for him and his wife,

•

all exercisable options remain exercisable until the applicable option expiration date, and

•

unvested options continue to become exercisable during the two-year severance period and thereafter remain exercisable until the applicable option expiration date.

The term “good reason” means any material breach of the employment agreement by Exelon, including (1) a failure to provide compensation and benefits required under the employment agreement, (2) causing Mr. Rowe to report to someone other than the board of directors, (3) any material adverse change in Mr. Rowe’s status, responsibilities or perquisites, or (4) any announcement by the board of directors without Mr. Rowe’s consent that Exelon is seeking a replacement for Mr. Rowe.

Mr. Rowe will receive the termination benefits described in “Change in Control Employment Agreements” below rather than the benefits described in the previous paragraph, if Exelon terminates Mr. Rowe without cause or he terminates with good reason, and

•

the termination occurs within 24 months after a change in control of Exelon or within 18 months after a Significant Acquisition (as each is defined below in “Change in Control Employment Agreements”), or

•

the termination occurs prior to the earlier of normal retirement or December 31, 2004, or

•

Mr. Rowe resigns before normal retirement because of the failure to be appointed or elected as the sole CEO and Chairman of the Board and as a member of the Exelon board of directors,

except that:

•

instead of receiving the target annual incentive for the year in which termination occurs, Mr. Rowe will receive an annual incentive award for the year in which termination occurs, based on the higher of the prior year’s annual incentive payment or the average annual incentives paid over the prior three years,

•

in determining the severance payment for Mr. Rowe, the average incentive awards for three years preceding the termination will be used rather than a two-year average,

•

following the three-year period during which welfare benefits are continued, Mr. Rowe and his wife will be eligible to receive post-retirement health care coverage, and

•

change in control benefits are not provided to Mr. Rowe for a termination of employment in the event of a Disaggregation (as defined in the “Change in Control Employment Agreements” section below).

With respect to a termination of employment during the change in control or Significant Acquisition periods described above, the following events will constitute additional grounds for termination for good reason: (1) a good faith determination by Mr. Rowe that he is substantially unable to perform, or that there has been a material reduction in, any of his duties, functions, responsibilities or authority, (2) the failure of any successor to assume

256

his employment agreement, (3) a relocation of Exelon’s office of more than 50 miles or (4) a 20% increase in the amount of time that Mr. Rowe must spend traveling for business outside of the Chicago area.

Mr. Rowe is subject to confidentiality restrictions and to non-competition, non-solicitation and non-disparagement restrictions continuing in effect for two years following his termination of employment.

Employment Agreement with Oliver D. Kingsley, Jr.

Exelon and Exelon Generation Company (Generation) entered into an amended employment agreement with Mr. Kingsley as of September 5, 2002, which restated his employment agreement with Commonwealth Edison Company in effect at the time of the merger forming Exelon and under which Mr. Kingsley will serve as senior executive vice president of Exelon. Mr. Kingsley’s employment agreement was further amended as of April 28, 2003, and by its current terms will expire as of October 31, 2004.

Under the amended employment agreement, Mr. Kingsley’s annual base salary will be $875,000, and his target performance award under the annual incentive plan will be 85% of his base salary, with a maximum payout of 170% of his base salary. Mr. Kingsley will be eligible to participate in long-term incentive, stock option, and other equity incentive plans, savings and retirement plans and welfare plans, and to receive fringe benefits on the same basis as peer executives of Exelon. Mr. Kingsley is entitled to 30 days of paid vacation per year.

In addition, Exelon will reimburse Mr. Kingsley for his daughter’s medical care expenses for a 15-year period (up to $100,000 in any year). The 15-year period will commence, at Mr. Kingsley’s option, on September 5, 2002, or on his termination or employment, or when coverage for his daughter otherwise lapses.

Mr. Kingsley received a grant of 35,000 shares of restricted stock on September 5, 2002. Twenty percent of the shares vest each January 1, beginning with January 1, 2003, subject to acceleration in the event Mr. Kingsley’s employment is terminated by Exelon (other than for cause) or his employment terminates due to his death or disability, or upon his retirement following expiration of his employment agreement.

Following Mr. Kingsley’s termination of employment for any reason, he will be eligible to elect retiree health coverage on the same terms as peer employees eligible for early retirement benefits. In addition, all restricted stock (other than the September 5, 2002 grant, which vests as described above) and all stock options will become fully vested. Options remain exercisable until (1) the option expiration date for options granted before January 1, 2002 or (2) the earlier of the fifth anniversary of his termination date or the option’s expiration date, for options granted after that date.

Mr. Kingsley’s employment agreement provides for an enhanced supplemental retirement benefit determined by treating him under the SERP as if he had 30 years of service as of October 31, 2002, plus (1) one additional year each October 31 during his employment and (2) an additional year for each year during the severance period described below. Severance payments will be included in compensation under the SERP. The enhanced SERP benefit will be paid to Mr. Kingsley following termination of employment.

Except as provided in the following paragraph, Mr. Kingsley will receive the following benefits if he should be terminated other than for cause, disability or death:

•

a prorated annual incentive award (at target) for the year in which termination occurs,

•

24 monthly payments, each equal to 1/12 the sum of (1) his base salary at the time of termination plus (2) his average annual incentive award payments for the two years preceding the termination date,

•

continuation of health, life, and disability coverage for two years after the date of termination, plus the right to elect retiree health coverage thereafter on the same terms as peer employees eligible for early retirement benefits,

257

•

all performance shares or units, deferred stock units or restricted share units become fully vested and nonforfeitable;

•

if Mr. Kingsley will be retiring at the end of the severance period, financial counseling services for the two-year severance period, and

•

outplacement services for at least six months.

Mr. Kingsley will (1) receive the termination benefits described in “Change in Control Employment Agreements” below, rather than the benefits described in the preceding paragraph, and (2) be eligible to receive retiree health benefits for himself and his eligible dependents, if Exelon terminates Mr. Kingsley without cause and

•

the termination occurs within 24 months after a change in control of Exelon or a Disaggregation (each as defined below in “Change in Control Employment Agreements”), or

•

within 18 months after a Significant Acquisition (as defined below in “Change in Control Employment Agreements”).

Mr. Kingsley’s employment agreement contains confidentiality requirements and also non-competition, non-solicitation and non-disparagement provisions, which are effective for two years following his termination of employment.

Change in Control Employment Agreements

Exelon has entered into change in control employment agreements with the named executive officers other than Messrs. Rowe and Kingsley, which generally protect such executives’ position and compensation levels for two years after a change in control. The agreements remain in effect until June 1, 2004, subject to an annual extension each June 1 if there has not been a change in control.

During the twenty-four month period following a change in control (or during the 18-month period following another significant corporate transaction affecting the executive’s business unit in which Exelon shareholders retain between 60% and 66²/3% control (a “Significant Acquisition”)) if a named executive officer resigns for good reason or if the executive’s employment is terminated by the company other than for cause or disability, the executive is entitled to the following:

•

the executive’s target annual incentive for the year in which termination occurs;

•

severance payments equal to three times the sum of (1) the executive’s base salary plus (2) the higher of the executive’s target annual incentive for the year of termination or the executive’s average annual incentive award payments for the two years preceding the termination;

•

a benefit equal to the amount payable under the SERP determined as if (1) the SERP benefit were fully vested, (2) the executive had three additional years of age and years of service (two years for executives hired after 2003) and (3) the severance pay constituted covered compensation for purposes of the SERP;

•

a cash payment equal to the actuarial equivalent present value of the unvested portion of the executive’s accrued benefits under Exelon’s defined benefit retirement plan;

•

all options, performance shares or units, deferred stock units, restricted stock, or restricted share units become fully vested, and options remain exercisable until (1) the option expiration date, for options granted before January 1, 2002 or (2) the earlier of the fifth anniversary of his termination date or the option’s expiration date, for options granted after that date;

•

life, disability, accident, health and other welfare benefit coverage continues for three years; and

•

outplacement services for at least twelve months.

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The change in control benefits are also provided if the executive is terminated other than for cause or disability, or terminates for good reason (1) after a tender offer or proxy contest commences, or after Exelon enters into an agreement, consummation of which would cause a change in control, and within one year after such termination a change in control does occur, or (2) within two years after a sale or spin-off of the executive’s business unit in contemplation of a change in control that actually occurs within 60 days after such sale or spin-off (a “Disaggregation”).

A change in control generally occurs (1) when any person acquires 20% of Exelon’s voting securities, (2) when the incumbent members of the board of directors (or new members nominated by a majority of incumbent directors) cease to constitute at least a majority of the members of the board, (3) upon consummation of a reorganization, merger or consolidation, or sale or other disposition of at least 50% of Exelon’s operating assets (excluding a transaction where Exelon stockholders retain at least 60% of the voting power) or (4) upon stockholder approval of a plan of complete liquidation or dissolution.

“Good reason,” under the change in control employment agreements generally includes any of the following occurring within 2 years after a change in control or Disaggregation or within 18 months after a Significant Acquisition: (1) a material reduction in salary, compensation or benefits, (2) failure of a successor to assume the agreement, or (3) a material breach of the agreement by the company, or (4) any of the following, but only after a change in control or Disaggregation: (a) a material adverse reduction in the nature or scope of the Executive’s office, position, duties and responsibilities, (b) required relocation of more than 50 miles, or (c) required travel of more than the greater of 24 days per year or at least 20% more than prior to the change in control or other trigger event. The mere occurrence of a Disaggregation is not “good reason.”

Executives who have entered into change in control employment agreements will be eligible to receive an additional payment to cover excise taxes imposed under Section 4999 of the Internal Revenue Code on “excess parachute payments” or under similar state or local law if the after-tax amount of payments and benefits subject to these taxes exceeds 110% of the “safe harbor” amount that would not subject the employee to these excise taxes. If the after-tax amount, however, is less than 110% of the safe harbor amount, payments and benefits subject to these taxes would be reduced or eliminated to equal the safe harbor amount.

Report of the Exelon Compensation Committee

ComEd and Generation are controlled subsidiaries of Exelon and as such do not have compensation committees. Instead, that function is fulfilled for ComEd and Generation by the Compensation Committee of the Exelon Board of Directors. The following is the report of the Exelon Compensation Committee

What is our compensation philosophy?Exelon’s executive compensation program is designed to motivate and reward senior management for achieving high levels of business performance and outstanding financial results. In 2003, Exelon continued to reward executives on the basis of compensation that is benchmarked and aligned with the best practices of high performing energy services companies and general industry firms. This philosophy reflects a commitment to attracting and retaining key executives to ensure continued focus on achieving long-term growth in shareholder value.

The Compensation Committee (the “Committee”), composed entirely of independent directors, is responsible for administering executive compensation programs, policies and practices. Exelon’s executive compensation program comprises three elements:

•

Base salary;

•

Annual incentives; and

•

Long-term incentives.

These components balance short-term and longer range business objectives and align executive financial rewards with those of Exelon’s shareholders.

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The Committee commissioned a study of compensation programs in the fall of 2003. This analysis was conducted by a leading external management compensation consulting firm and included an assessment of business plans, strategic goals, peer companies and competitive compensation levels benchmarked with the external market.

The study results indicated that the mix of compensation components (i.e., salary, annual and long-term incentives) is effectively aligned with the best practices of the external market. Exelon’s pay-for-performance philosophy places an emphasis on pay-at-risk. Pay will exceed market levels when excellent performance is achieved. Failure to achieve target goals will result in below market pay.

Base salaries for Exelon’s executives are determined based on individual performance with reference to the salaries of executives in similar positions in general industry, and where appropriate, the energy services sector. Executive salaries are targeted to approximate the median (50th percentile) salary levels of the companies identified and surveyed.

Mr. Rowe’s 2003 Base Salary: The independent directors of the board, on the recommendations of the Compensation and Corporate Governance Committees, determined Mr. Rowe’s base salary for serving as the Chief Executive Officer by considering:

•

A review of benchmark levels of base pay, which were provided by external consulting firms, and

•

performance achieved against financial and operational goals, and

•

the implementation of Exelon’s strategic plans.

Mr. Rowe’s annualized base salary was increased to $1,200,000 effective March 1, 2003.

Other Named Executives’ 2003 Base Salaries:The base salaries of the other named executive officers listed in the Summary Compensation Table were determined based upon individual performance and by considering comparable compensation data from the industry surveys referred to above.

Exelon establishes corporate and business unit measures each year which are based on factors necessary to achieve strategic business objectives. These measures are incorporated into financial, customer and internal indicators designed to measure corporate and business unit performance.

The annual incentive awards paid to Exelon executives for 2003 were determined in accordance with the Exelon incentive programs. Annual incentives were paid to executives based on a combination of the achievement of pre-determined corporate and business unit-specific measures and individual performance. The incentive plan was designed to tie executive annual incentives to the achievement of key goals of Exelon, as applicable, and the executive’s particular business unit.

For 2003, Mr. Rowe’s annual incentive payout was determined using the Earnings Per Share corporate performance measure.

2003 Annual Incentive Award: In evaluating Mr. Rowe’s performance, the directors considered the overall performance of Exelon against the measures that were achieved under the applicable incentive program. The board also considered the leadership demonstrated in positioning Exelon for the future.

Exelon decided to take select one-time charges (primarily non-cash) in 2003, which could have affected payouts under the Company’s Annual Incentive Program. These events significantly reduced Exelon’s earnings recorded under Generally Accepted Accounting Principles (GAAP).

In reviewing the issue, the Committee agreed that basing the incentive award on GAAP earnings would be inconsistent with the Company’s strong operating performance and Exelon’s robust stock price throughout the

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year. However, since Earnings Per Share is such an integral component of the award, the Committee concluded that reward should be adjusted to reflect the adverse effects of these significant events.

The Committee, after considering these issues, permitted the exclusion of the one-time events described above from the earnings calculation used for the 2003 incentive awards based upon Exelon’s continued strong operating and earnings performance for the year.

The Committee also accepted management’s recommendation to impose some accountability for these one-time events. Award payouts for all participants were reduced by 20 to 30 percent. Mr. Rowe, other named executives and senior executives absorbed a 30 percent reduction.

Other Named Executive Officers’ 2003 Annual Incentives: The final 2003 incentive plan payouts as approved by the Committee for the other named executive officers listed in the Summary Compensation Table were determined in accordance with the applicable incentive programs and each individual’s performance.

Exelon established a long-term incentive program that includes a combination of non-qualified stock options (60%) and performance shares (40%). Exelon granted long-term incentives in the form of stock options to key management employees, including the named executive officers, effective January 27, 2003. The purpose of stock options is to align compensation directly to increases in shareholder value. Individuals receiving stock options are provided the right to buy a fixed number of shares of Exelon common stock at the closing price of such stock on the grant date. Options typically vest over a four-year period and have a term of ten years.

Stock Option Awards: Mr. Rowe received a grant of 175,000 non-qualified stock options on January 27, 2003. Other senior executives and other executives received grants on January 27, 2003 to motivate executives to achieve stock appreciation in support of shareholder value.

Exelon Performance Share Awards: Long-term incentives were awarded in the form of restricted stock to retain key executives engaged in positioning Exelon Corporation. Awards were determined based upon the successful completion of strategic goals designed to achieve long-term business success and increased shareholder value. Depending on Exelon Corporation’s performance each year, the Committee could award performance shares with prohibitions on sale or transfer until the restrictions lapse.

Performance shares are paid in Exelon stock: 33% vest upon award date, 33% after the second year and 34% after the third year.

The 2003 Long Term Performance Share Program was based on Total Shareholder Return (TSR) comparing Exelon to companies listed on the Dow Jones Utility Index and the Standard and Poor’s 500 Index using a three-year TSR compounded monthly. The other component in determining the award was an assessment by the Committee on strategic goals emphasizing growth in cash and earnings.

The board of directors approved Mr. Rowe’s Performance Share Award of 42,000 shares. All other executives named also received Performance Share Awards.

Under Section 162(m) of the Internal Revenue Code (“Code”), executive compensation in excess of $1 million paid to a chief executive officer or other person among the four highest compensated officers is generally not deductible for purposes of corporate federal income taxes. However, “qualified performance-based compensation” which is paid pursuant to a plan meeting certain requirements of the Code and applicable regulations remains deductible. The Committee intends to continue reliance on performance-based compensation programs, consistent with sound executive compensation policy. Such programs will be designed to fulfill, in the best possible manner, future corporate business objectives. The Committee’s policy has been to seek to cause executive incentive compensation to qualify as “performance-based” in order to preserve its deductibility for federal income tax purposes to the extent possible without sacrificing flexibility in designing appropriate compensation programs. However, in order to provide executives with appropriate incentives, the Committee may also determine, in light of all applicable circumstances, that it would be in the best interests of Exelon for

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awards to be paid under certain of its incentive compensation programs or otherwise in a manner that would not satisfy the requirements to qualify as performance-based compensation under Code Section 162(m).

For 2003, the Committee approved an annual incentive award plan design that provided for the final awards paid to named executive officers to be adjusted based on their individual contribution to Exelon’s financial and operational results. In approving this approach, the Committee concluded that the benefits of exercising discretion in assessing individual performance outweighed the impact of these incentive payments not qualifying as performance-based compensation under Section 162(m).

The portion of compensation that does not qualify under Code Section 162(m) and is not deferred, will not be deductible by Exelon for purposes of corporate federal income taxes. Mr. Rowe has elected to defer 100% of his long-term incentive award payable in 2004.

Exelon is seeking at the 2004 Annual Meeting approval from the shareholders of a qualified performance-based annual incentive program for 2004 for named executive officers and select senior management that will meet the requirements under Code Section 162(m) and preserve deductibility of the incentive program for corporate federal income tax purposes.

Compensation Committee:

Edward A. Brennan, Chairman

Rosemarie B. Greco

Ronald Rubin

Richard L. Thomas

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Stock Performance Graph

The performance graph below illustrates a five year comparison of cumulative total returns based on an initial investment of $100 in PECO Energy Company common stock that was exchanged for Exelon Corporation common stock in the share exchange on October 20, 2000 as compared with the S&P 500 Stock Index and the S&P Utility Average for the period 1999 through 2003.

This performance chart assumes:

•

$100 invested on December 31, 1998 in PECO Energy Company common stock in the S&P 500 Stock Index and in the S&P Utility Index.

•

All dividends are reinvested.

•

PECO Energy common stock exchanged for Exelon Corporation common stock on a 1:1 basis on October 20, 2000.


	1998		1999		2000		2001		2002		2003
Exelon Corporation	$	100.00	$	85.35	$	175.81	$	123.94	$	141.35	$	183.55
S&P 500		100.00		121.02		109.99		96.98		75.60		97.24
S&P Utilities		100.00		90.91		142.73		99.45		69.67		87.78

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” in the 2004 Exelon Proxy Statement.

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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	13,621,723	$	49.32	10,592,183
Equity compensation plans not approved by security holders	531,970		41.11	—

Total	14,153,693	$	49.01	10,592,183

(a)	Excludes securities to be issued upon exercise of outstanding options.

ComEd

Over 99% of ComEd’s common stock is held indirectly by Exelon. Accordingly, the only beneficial holder of more than five percent of ComEd’s voting securities is Exelon, and none of the directors or executive officers of ComEd hold any of their voting securities.

The following table presents the beneficial ownership of Exelon’s common stock by ComEd’s directors and executive officers.


Name		Beneficially owned shares (a)	Shares that may be acquired (b)	Deferred or phantom shares (c)	Total shares
Wellington Management Company, LLP		22,024,775			22,024,775	(d)
Barclays Global Investors, NA		20,987,379			20,987,379	(e)
Edward A. Brennan	Director	3,984	—	8,541	12,525
M. Walter D’Alessio	Director	6,173	—	13,698	19,871
Nicholas DeBenedictis	Director	—	—	1,615	1,615
Bruce DeMars	Director	4,421	—	3,576	7,997
G. Fred DiBona, Jr.	Director	1,450	—	6,699	8,149
Nelson A. Diaz	Director	—	—	—	—
Sue L. Gin	Director	12,616	—	6,388	19,004
Rosemarie B. Greco	Director	1,000	—	7,848	8,848
Edgar D. Jannotta	Director	6,620	—	11,817	18,437
John M. Palms, Ph.D	Director	1,258	—	11,143	12,401
John W. Rogers, Jr.	Director	3,687	—	6,200	9,887
Ronald Rubin	Director	7,363	—	13,958	21,321
Richard L. Thomas	Director	10,607	—	10,264	20,871
Michael Bemis	Director and Officer	6,773	—	130	6,903
Pamela B. Strobel	Director and Officer	186,828	47,000	25,439	259,267
John W. Rowe	Director and Officer	1,091,949	197,917	106,497	1,396,363
Oliver D. Kingsley, Jr.	Director and Officer	371,529	71,667	70,043	513,239
Robert S. Shapard	Director and Officer	32,094	40,333	895	73,322
Frank M. Clark	Director and Officer	95,846	31,917	12,801	140,564
Total Director and Officers as a Group (22) (f)		2,043,533	441,601	340,957	2,826,091

(a)	These shares include non-qualified stock options that are exercisable within 60 days of December 31, 2003.

(b)	These shares include shares of Exelon’s common stock that can be acquired upon the exercise of non-qualified stock options granted under Exelon plans that are not exercisable within 60 days of December 31, 2003.

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(c)	These shares include shares not considered to be beneficially owned under the rules of the Securities and Exchange Commission because they are held in various Exelon plans.

(d)

In a Form 13G filed with the SEC on February 12, 2004 an investment adviser, Wellington Management Company, LLP 75 State Street, Boston, MA 02109, disclosed that as of December 31, 2003, it was the beneficial owner of 22,024,775 Exelon shares, or approximately 6.735% of Exelon’s issued and outstanding common shares. Wellington disclosed that it shared voting power as to 12,479,889 shares and share dispositive power as to 22,045,775 shares.

(e)

In a Form 13G filed with the SEC on February 17, 2004, a bank, Barclays Global Investors, NA, 45 Fremont Street, San Francisco, CA 94105, and its affiliates, including banks, investment advisers, and broker/dealers, disclosed that as of December 31, 2003, they were the beneficial owners of an aggregate of 20,987,379 Exelon shares, or approximately 6.41% of Exelon’s issued and outstanding shares.

(f)	Beneficial ownership of directors and executive officers as a group represents approximately 0.9% of the outstanding shares of Exelon common stock. The total ownership as a group includes executive officers who are not named in the table.

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 2004 PECO Information Statement.

No PECO securities are authorized for issuance under equity compensation plans. For information about Exelon securities authorized for issuance to PECO employees under Exelon equity compensation plans, see above under “Exelon – Securities Authorized Under Equity Compensation Plans.”

Generation

Generation is a wholly owned indirect subsidiary of Exelon. The following table presents the beneficial ownership of Exelon’s common stock by Generation’s directors and executive officers.


Name		Beneficially owned shares (a)	Shares that may be acquired (b)	Deferred or phantom shares (c)	Total shares
Wellington Management Company, LLP		22,045,775			22,045,775	(d)
Barclays Global Investors, NA		20,987,379			20,987,379	(e)
Edward A. Brennan	Director	3,984	—	8,541	12,525
M. Walter D’Alessio	Director	6,173	—	13,698	19,871
Nicholas DeBenedictis	Director	—	—	1,615	1,615
Bruce DeMars	Director	4,421	—	3,576	7,997
G. Fred DiBona, Jr.	Director	1,450	—	6,699	8,149
Nelson A. Diaz	Director	—	—	—	—
Sue L. Gin	Director	12,616	—	6,388	19,004
Rosemarie B. Greco	Director	1,000	—	7,848	8,848
Edgar D. Jannotta	Director	6,620	—	11,817	18,437
John M. Palms, Ph.D	Director	1,258	—	11,143	12,401
John W. Rogers, Jr.	Director	3,687	—	6,200	9,887
Ronald Rubin	Director	7,363	—	13,958	21,321
Richard L. Thomas	Director	10,607	—	10,264	20,871
Oliver D. Kingsley, Jr.	Director and Officer	371,529	71,667	70,043	513,239
John W. Rowe	Director and Officer	1,091,949	197,917	106,497	1,396,363
John L. Skolds	Director and Officer	137,588	45,000	25,321	207,909
Ian McLean	Director and Officer	158,427	45,096	2,096	205,619
John F. Young	Director and Officer	2,500	15,000	—	17,500
Robert S. Shapard	Director and Officer	32,094	40,333	895	73,322
Total Directors and Officers as a Group (21) (f)		1,956,389	445,638	316,774	2,718,801

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(a)	These shares include non-qualified stock options that are exercisable within 60 days of December 31, 2003.

(b)	These shares include shares of Exelon’s common stock that can be acquired upon the exercise of non-qualified stock options granted under Exelon plans that are not exercisable within 60 days of December 31, 2003.

(c)	These shares include shares not considered to be beneficially owned under the rules of the Securities and Exchange Commission because they are held in various Exelon plans.

(d)

In a Form 13G filed with the SEC on February 12, 2004 an investment adviser, Wellington Management Company, LLP 75 State Street, Boston, MA 02109, disclosed that as of December 31, 2003, it was the beneficial owner of 22,045,775 Exelon shares, or approximately 6.735% of Exelon’s issued and outstanding common shares. Wellington disclosed that it shared voting power as to 12,479,889 shares and share dispositive power as to 22,045,775 shares.

(e)

(f)	Beneficial ownership of directors and executive officers as a group represents approximately 0.8% of the outstanding shares of Exelon common stock. The total ownership as a group includes executive officers who are not named in the table.

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” in the 2004 Exelon Proxy Statement.

ComEd

None.

PECO

None.

Generation

None.

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

Exelon

The information required by Item 14 is incorporated herein by reference to the information labeled “INDEPENDENT PUBLIC ACCOUNTANTS” in the 2004 Exelon Proxy Statement.

ComEd

ComEd is an indirect controlled subsidiary of Exelon and does not have a separate audit committee. Instead, that function is fulfilled for ComEd by the Exelon Audit Committee. In July 2002 the Exelon Audit Committee adopted a policy for pre-approval of services to be performed by the independent accountants. The committee pre-approves annual budgets for audit, audit-related and tax compliance and planning services. The

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services that the committee will consider include services that do not impair the accountant’s independence and add value to the audit, including audit services such as attest services and scope changes in the audit of the financial statements, audit-related services such as accounting advisory services related to proposed transactions and new accounting pronouncements, the issuance of comfort letters and consents in relation to financings, the provision of attest services in relation to regulatory filings and contractual obligations, and tax compliance and planning services. With respect to non-budgeted services in amounts less than $500,000, the committee delegated authority to the committee’s chairman to pre-approve such services. All other services must be pre-approved by the committee. The committee receives quarterly reports on all fees paid to the independent accountants. None of the services provided by the independent accountants was provided pursuant to the de minimis exception to the pre-approval requirements contained in the SEC’s rules.

The following table presents fees for professional audit services rendered by PricewaterhouseCoopers LLP for the audit of ComEd’s annual financial statements for the years ended December 31, 2003 and 2002, and fees billed for other services rendered by PricewaterhouseCoopers LLP during those periods. These fees include an allocation of amounts billed directly to Exelon Corporation. Certain amounts for 2002 have been reclassified to conform to 2003 presentation.


	Year Ended December 31,
(in thousands)	2003		2002
Audit fees	$	984	$	1,030
Audit related fees (1)		196		96
Tax fees (2)		333		153
All other fees (3)		—		139

(1)	Audit related fees consist of assurance and related services that are reasonably related to the performance of the audit or review of ComEd’s financial statements. This category includes fees for regulatory work, depreciation studies and internal control projects.

(2)	Tax fees consist of the aggregate fees billed for professional services rendered by PricewaterhouseCoopers LLP for tax compliance, tax advice, and tax planning.

(3)	All other fees reflects work performed in connection with ComEd’s business continuity planning.

PECO

The information required by Item 14 is incorporated herein by reference to the information labeled “INDEPENDENT PUBLIC ACCOUNTANTS” in the 2004 PECO Information Statement.

Generation

Generation is an indirect controlled subsidiary of Exelon and does not have a separate audit committee. Instead, that function is fulfilled for Generation by the Exelon Audit Committee. In July 2002 the Exelon Audit Committee adopted a policy for pre-approval of services to be performed by the independent accountants. The committee pre-approves annual budgets for audit, audit-related and tax compliance and planning services. The services that the committee will consider include services that do not impair the accountant’s independence and add value to the audit, including audit services such as attest services and scope changes in the audit of the financial statements, audit-related services such as accounting advisory services related to proposed transactions and new accounting pronouncements, the issuance of comfort letters and consents in relation to financings, the provision of attest services in relation to regulatory filings and contractual obligations, and tax compliance and planning services. With respect to non-budgeted services in amounts less than $500,000, the committee delegated authority to the committee’s chairman to pre-approve such services. All other services must be pre-approved by the committee. The committee receives quarterly reports on all fees paid to the independent accountants. None of the services provided by the independent accountants was provided pursuant to the de minimis exception to the pre-approval requirements contained in the SEC’s rules.

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The following table presents fees for professional audit services rendered by PricewaterhouseCoopers LLP for the audit of Generation’s annual financial statements for the years ended December 31, 2003 and 2002, and fees billed for other services rendered by PricewaterhouseCoopers LLP during those periods. These fees include an allocation of amounts billed directly to Exelon Corporation. Certain amounts for 2002 have been reclassified to conform to 2003 presentation.


	Year Ended December 31,
(in thousands)	2003		2002
Audit fees	$	1,477	$	1,598
Audit related fees (1)		441		166
Tax fees (2)		331		812
All other fees (3)		—		226

(1)	Audit related fees consist of assurance and related services that are reasonably related to the performance of the audit or review of Generation’s financial statements. This category includes fees for purchase accounting reviews, audits of employee benefit plans and internal control projects.

(2)	Tax fees consist of the aggregate fees billed for professional services rendered by PricewaterhouseCoopers LLP for tax compliance, tax advice, and tax planning.

(3)	All other fees reflects work performed in connection with Generation’s business continuity planning.

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PART IV

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

Report of Independent Auditors 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 28, 2004, appearing in the 2003 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 28, 2004

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(a)	FinancialStatements and Financial Statement Schedules

(1)	Exelon

(i)	Financial Statements

		Consolidated Statements of Income for the years 2003, 2002 and 2001

		Consolidated Statements of Cash Flows for the years 2003, 2002 and 2001

		Consolidated Balance Sheets as of December 31, 2003 and 2002

		Consolidated Statements of Changes in Shareholders’ Equity for the years 2003, 2002 and 2001

		Consolidated Statements of Comprehensive Income for the years 2003, 2002 and 2001

		Notes to Consolidated Financial Statements

(ii)	Financial Statement Schedule

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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
Description	Balance at Beginning of Year		Additions and adjustments					Deductions			Balance at End of Year
Description	Balance at Beginning of Year		Charged to Cost and Expenses		Charged to Other Accounts			Deductions			Balance at End of Year
*For The Year Ended December 31, 2003*

Allowance for uncollectible accounts	$	132	$	103	$	(9	)	$	116	(a)	$	110

Reserve for obsolete materials	$	18	$	4	$	1		$	5		$	18

*For The Year Ended December 31, 2002*

Allowance for uncollectible accounts	$	213	$	129	$	—		$	210	(a)	$	132

Reserve for obsolete materials	$	18	$	9	$	4		$	13		$	18

*For The Year Ended December 31, 2001*

Allowance for uncollectible accounts	$	200	$	145	$	—		$	132	(a)	$	213

Reserve for obsolete materials	$	103	$	16	$	—		$	101		$	18

(a)	Write-off of individual accounts receivable.

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(2)	ComEd

(i)	Financial Statements

		Consolidated Statements of Income for the years 2003, 2002 and 2001

		Consolidated Statements of Cash Flows for the years 2003, 2002 and 2001

		Consolidated Balance Sheets as of December 31, 2003 and 2002

		Consolidated Statements of Changes in Shareholders’ Equity for the years 2003, 2002 and 2001

		Consolidated Statements of Comprehensive Income for the years 2003, 2002 and 2001

		Notes to Consolidated Financial Statements

(ii)	Financial Statement Schedule

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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
Description	Balance at Beginning of Year		Additions and adjustments				Deductions		Restructuring Transfers (a)		Balance at End of Year
Description	Balance at Beginning of Year		Charged to Cost and Expenses		Charged to Other Accounts		Deductions		Restructuring Transfers (a)		Balance at End of Year

*For The Year Ended December 31, 2003*

Allowance for uncollectible accounts	$	24	$	46	$	—	$	54	$	—	$	16

Reserve for obsolete materials	$	5	$	4	$	—	$	1	$	—	$	8

*For The Year Ended December 31, 2002*

Allowance for uncollectible accounts	$	49	$	50	$	—	$	75	$	—	$	24

Reserve for obsolete materials	$	6	$	—	$	—	$	1	$	—	$	5

*For The Year Ended December 31, 2001*

Allowance for uncollectible accounts	$	60	$	42	$	1	$	54	$	—	$	49

Reserve for obsolete materials	$	98	$	—	$	—	$	14	$	78	$	6

(a)	Represents amounts transferred as part of the 2001 Corporate Restructuring. See ITEM 8. Financial Statements and Supplementary Information – ComEd – Note 1 of Notes to Consolidated Financial Statements.

273


(3)	PECO

(i)	Financial Statements

		Consolidated Statements of Income for the years 2003, 2002 and 2001

		Consolidated Statements of Cash Flows for the years 2003, 2002 and 2001

		Consolidated Balance Sheets as of December 31, 2003 and 2002

		Consolidated Statements of Changes in Shareholders’ Equity for the years 2003, 2002 and 2001

		Consolidated Statements of Comprehensive Income for the years 2003, 2002 and 2001

		Notes to Consolidated Financial Statements

(ii)	Financial Statement Schedule

274

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
Description	Balance at Beginning of Year		Additions and adjustments				Deductions			Restructuring Transfers (a)		Balance at End of Year
Description	Balance at Beginning of Year		Charged to Cost and Expenses		Charged to Other Accounts		Deductions			Restructuring Transfers (a)		Balance at End of Year

*For The Year Ended December 31, 2003*

Allowance for uncollectible accounts	$	72	$	52	$	8	$	60	(b)	$	—	$	72

*For The Year Ended December 31, 2002*

Allowance for uncollectible accounts	$	110	$	45	$	—	$	83	(b)	$	—	$	72

Reserve for obsolete materials	$	1	$	—	$	—	$	1		$	—	$	—

*For The Year Ended December 31, 2001*

Allowance for Uncollectible Accounts	$	131	$	69	$	—	$	67	(b)	$	23	$	110

Reserve for obsolete materials	$	3	$	6	$	—	$	7		$	1	$	1

(a)	Represents amounts transferred as part of the 2001 Corporate Restructuring. See ITEM 8. Financial Statements and Supplementary Information – PECO – Note 1 of Notes to the Consolidated Financial Statements.

(b)	Write-off of individual accounts receivable.

275


(4)	Generation

(i)	Financial Statements

		Consolidated Statements of Income for the years 2003, 2002 and 2001

		Consolidated Statements of Cash Flow for the years 2003, 2002 and 2001

		Consolidated Balance Sheets as of December 31, 2003 and 2002

		Consolidated Statements of Changes in Divisional/Member’s Equity for the years 2003, 2002 and 2001

		Consolidated Statements of Comprehensive Income for the years 2003, 2002 and 2001

		Notes to Consolidated Financial Statements

(ii)	Financial Statement Schedule

276

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

Schedule II – Valuation and Qualifying Accounts

(in millions)


Column A	Column B		Column C					Column D			Column E
Description	Balance at Beginning of Year		Additions and adjustments					Deductions			Balance at End of Year
Description	Balance at Beginning of Year		Charged to Cost and Expenses		Charged to Other Accounts			Deductions			Balance at End of Year

*For The Year Ended December 31, 2003*

Allowance for uncollectible accounts	$	22	$	1	$	(9	)	$	—		$	14

Reserve for obsolete materials	$	13	$	1	$	—		$	5		$	9

*For The Year Ended December 31, 2002*

Allowance for uncollectible accounts	$	17	$	26	$	—		$	21	(a)	$	22

Reserve for obsolete materials	$	12	$	10	$	3		$	12		$	13

*For The Year Ended December 31, 2001*

Allowance for uncollectible accounts	$	2	$	16	$	—		$	1	(a)	$	17

Reserve for obsolete materials	$	79	$	11	$	—		$	78		$	12

(a)	Write-off of individual accounts receivable.

277

(b)	Reports on Form 8-K

Exelon, ComEd, PECO and/or Generation filed Current Reports on Form 8-K during the fourth quarter of 2003 regarding the following items:


Date of Earliest Event Reported		Description of Item Reported and Filer(s)
October 1, 2003		“ITEM 5. OTHER EVENTS” filed by Exelon and Generation, regarding Generation’s exercise of certain termination options under its purchased power agreements with Midwest Generation.

October 3, 2003		“ITEM 5. OTHER EVENTS” filed by Exelon and Generation, announcing that Exelon will buy British Energy’s fifty percent interest in AmerGen.

October 31, 2003		“ITEM 5. OTHER EVENTS” filed by Exelon, ComEd, PECO and Generation, announcing the replacement of their $1.5 billion credit facility and providing additional information regarding the debt outstanding as of September 30, 2003.

November 3, 2003		“ITEM 5. OTHER EVENTS” filed by Exelon, ComEd and Generation, announcing Exelon’s agreement to acquire the operating assets of Illinois Power from Dynegy, Inc.

November 10, 2003		“ITEM 5. OTHER EVENTS” filed by Exelon, ComEd and Generation, announcing modifications to legislation they were seeking to facilitate Exelon’s proposed acquisition of Illinois Power.

November 22, 2003		“ITEM 5. OTHER EVENTS” filed by Exelon, ComEd and Generation, announcing that the Illinois General Assembly did not act in the fall legislative session to approve the legislation necessary to facilitate Exelon’s proposed acquisition of Illinois Power. In the absence of the legislation, Dynegy and Exelon terminated the agreement through which Exelon would have acquired substantially all of the assets and liabilities of Illinois Power.

November 25, 2003		“ITEM 5. OTHER EVENTS” filed by Exelon and Generation regarding the completion of a series of transactions resulting in Generation and Reservoir each indirectly owning a 50% interest in Sithe and the purchase by Exelon of interests in synthetic fuel-producing facilities.

December 15, 2003		“ITEM 5. OTHER EVENTS” filed by Exelon announcing that it has entered into an agreement to sell Exelon Thermal to Macquarie Bank Limited of Australia.

December 22, 2003		“ITEM 5. OTHER EVENTS” filed by Exelon and Generation regarding Generation’s purchase of British Energy’s fifty percent interest in AmerGen Energy Company, LLC. As a result, Generation is now the sole owner of AmerGen Energy Company, LLC.

278

(c)

Exhibits

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


Exhibit No.		Description
2-1		Amended and Restated Agreement and Plan of Merger dated as of October 20, 2000, among PECO Energy Company, Exelon Corporation and Unicom Corporation (File No. 1-01401, PECO Energy Company Form 10-Q for the quarter ended September 30, 2000, Exhibit 2-1).

3-1		Articles of Incorporation of Exelon Corporation (Registration Statement No. 333-37082, Form S-4, Exhibit 3-1).

3-2		Amended and Restated Bylaws of Exelon Corporation, adopted January 27, 2004.

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		First Amended and Restated Operating Agreement of Exelon Generation Company, LLC executed as of January 1, 2001.

4-1		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).

279


Exhibit No.		Description
4-1-1		Supplemental Indentures to PECO Energy Company’s First and Refunding Mortgage:


Dated as of	File Reference	Exhibit No.
May 1, 1927	2-2881	B-1(c)
March 1, 1937	2-2881	B-1(g)
December 1, 1941	2-4863	B-1(h)
November 1, 1944	2-5472	B-1(i)
December 1, 1946	2-6821	7-1(j)
September 1, 1957	2-13562	2(b)-17
May 1, 1958	2-14020	2(b)-18
March 1, 1968	2-34051	2(b)-24
March 1, 1981	2-72802	4-46
March 1, 1981	2-72802	4-47
December 1, 1984	1-01401, 1984 Form 10-K	4-2(b)
April 1, 1991	1-01401, 1991 Form 10-K	4(e)-76
December 1, 1991	1-01401, 1991 Form 10-K	4(e)-77
June 1, 1992	1-01401, June 30, 1992 Form 10-Q	4(e)-81
March 1, 1993	1-01401, 1992 Form 10-K	4(e)-86
May 1, 1993	1-01401, March 31, 1993 Form 10-Q	4(e)-88
May 1, 1993	1-01401, March 31, 1993 Form 10-Q	4(e)-89
August 15, 1993	1-01401, Form 8-A dated August 19, 1993	4(e)-92
May 1, 1995	1-01401, Form 8-K dated May 24, 1995	4(e)-96
September 15, 2002	1-01401, September 30, 2002 Form 10-Q	4-1
October 1, 2002	1-01401, September 30, 2002 Form 10-Q	4-2
April 15, 2003	0-16844, March 31, 2003 Form 10-Q	4-1


4-2		Exelon Corporation Dividend Reinvestment and Stock Purchase Plan (Registration Statement No. 333-84446, Form S-3, Prospectus).

4-3		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).

280


Exhibit No.		Description
4-3-1		Supplemental Indentures to aforementioned Commonwealth Edison Mortgage.


Dated as of	File Reference	Exhibit No.
August 1, 1946	2-60201, Form S-7	2-1
April 1, 1953	2-60201, Form S-7	2-1
March 31, 1967	2-60201, Form S-7	2-1
April 1,1967	2-60201, Form S-7	2-1
February 28, 1969	2-60201, Form S-7	2-1
May 29, 1970	2-60201, Form S-7	2-1
June 1, 1971	2-60201, Form S-7	2-1
April 1, 1972	2-60201, Form S-7	2-1
May 31, 1972	2-60201, Form S-7	2-1
June 15, 1973	2-60201, Form S-7	2-1
May 31, 1974	2-60201, Form S-7	2-1
June 13, 1975	2-60201, Form S-7	2-1
May 28, 1976	2-60201, Form S-7	2-1
June 3, 1977	2-60201, Form S-7	2-1
May 17, 1978	2-99665, Form S-3	4-3
August 31, 1978	2-99665, Form S-3	4-3
June 18, 1979	2-99665, Form S-3	4-3
June 20, 1980	2-99665, Form S-3	4-3
April 16, 1981	2-99665, Form S-3	4-3
April 30, 1982	2-99665, Form S-3	4-3
April 15, 1983	2-99665, Form S-3	4-3
April 13, 1984	2-99665, Form S-3	4-3
April 15, 1985	2-99665, Form S-3	4-3
April 15, 1986	33-6879, Form S-3	4-9
June 15, 1990	33-38232, Form S-3	4-12
October 1, 1991	33-40018, Form S-3	4-13
October 15, 1991	33-40018, Form S-3	4-14
May 15, 1992	33-48542, Form S-3	4-14
September 15, 1992	33-53766, Form S-3	4-14
February 1, 1993	1-1839, 1992 Form 10-K	4-14
April 1, 1993	33-64028, Form S-3	4-12
April 15, 1993	33-64028, Form S-3	4-13
June 15, 1993	1-1839, Form 8-K dated May 21, 1993	4-1
July 15, 1993	1-1839, Form 10-Q for quarter ended June 30, 1993.	4-1
January 15, 1994	1-1839, 1993 Form 10-K	4-15
December 1, 1994	1-1839, 1994 Form 10-K	4-16
June 1, 1996	1-1839, 1996 Form 10-K	4-16
March 1, 2002	1-1839, 2001 Form 10-K	4-4-1
May 20, 2002
June 1, 2002
October 7, 2002
January 13, 2003	1-1839, Form 8-K dated January 22, 2003	4-4
March 14, 2003	1-1839, Form 8-K dated April 7, 2003	4-4
August 13, 2003	1-1839, Form 8-K dated August 25, 2003	4-4

281


Exhibit No.		Description
4-3-2		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).

4-3-3		Instrument dated as of January 31, 1996, under the provisions of the Mortgage dated July 1, 1923 and Indentures Supplemental thereto, regarding individual trustee (File No. 1-1839, 1995 Form 10-K, Exhibit 4-29).

4-4		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).

4-4-1		Supplemental Indentures to aforementioned Indenture.


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


4-5		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).

4-6		Indenture dated December 19, 2003 between Generation and Wachovia Bank, National Association.

4-7		Indenture to Subordinated Debt Securities dated as of June 24, 2003 between PECO Energy Company, as Issuer, and Wachovia Bank National Association, as Trustee (File No. 0-16844, PECO Energy Company Form 10-Q for the quarter ended June 30, 2003, Exhibit 4.1).

4-8		Preferred Securities Guarantee Agreement between PECO Energy Company, as Guarantor, and Wachovia Trust Company, National Association, as Trustee, dated as of June 24, 2003 (File No. 0-16844, PECO Energy Company Form 10-Q for the quarter ended June 30, 2003, Exhibit 4.2).

4-9		PECO Energy Capital Trust IV Amended and Restated Declaration of Trust among PECO Energy Company, as Sponsor, Wachovia Trust Company, National Association, as Delaware Trustee and Property Trustee, and J. Barry Mitchell, George R. Shicora and Charles S. Walls as Administrative Trustees dated as of June 24, 2003 (File No. 0-16844, PECO Energy Company Form 10-Q for the quarter ended June 30, 2003, Exhibit 4.3).

10-1		Stock Purchase Agreement among Exelon (Fossil) Holdings, Inc., as Buyer and The Stockholders of Sithe Energies, Inc., as Sellers, and Sithe Energies, Inc. (File No. 0-16844, PECO Energy Company Form 10-Q for the quarter ended September 30, 2000, Exhibit 10-1).

10-2		$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 (File No. 333-85496, Exelon Generation Company, LLC 2002 Form 10-K, Exhibit 10-2).

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).

282


Exhibit No.		Description
10-6		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).

10-7		Amended and restated employment agreement between Exelon Corporation, Exelon Generation Company, LLC and Oliver D. Kingsley, Jr. dated as of April 29, 2003.*

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).

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).

283


Exhibit No.		Description
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).

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).

284


Exhibit No.		Description
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).

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 (File No. 1-16169, Commonwealth Edison Company 2002 Form 10-K, Exhibit 10-41).

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 (File No. 1-16169, Commonwealth Edison Company 2002 Form 10-K, Exhibit 10-41-1).

285


Exhibit No.		Description
10-42		Retirement and Separation between Exelon Corporation, PECO Energy Company and Kenneth G. Lawrence, dated as of May 11, 2003 (File No. 0-16844, PECO Energy Company September 30, 2003 Form 10-Q, Exhibit 10.1).

10-43		Purchase and Sale Agreement dated as of October 10, 2003 between British Energy Investment Ltd. and Exelon Generation Company, LLC relating to the sale and purchase of 100% of the shares of British Energy US Holdings Inc. (File Nos. 1-16169 and 333-85496, Exelon Corporation and Exelon Generation Company, LLC September 30, 2003 Form 10-Q, Exhibit 10.2).

10-44		$750,000,000 364-Day Credit Agreement dated as of October 31, 2003 among Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC as Borrowers and Various Financial Institutions as Lenders.

10-44-1		$750,000,000 Three Year Credit Agreement dated as of October 31, 2003 among Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC as Borrowers and Various Financial Institutions as Lenders.

10-45		$850,000,000 Credit Agreement dated as of September 29, 2003 among Exelon Generation Company, LLC as Borrower and Various Financial Institutions as Lenders.

14		Exelon Code of Conduct Subsidiaries

21-1		Exelon Corporation (File No. 1-16169, 2002 Form 10-K, Exhibit 21-1).

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).

21-4		Exelon Generation Company, LLC

		Consent of Independent Auditors

23-1		Exelon Corporation

23-2		Commonwealth Edison Company

23-3		PECO Energy Company

		Power of Attorney

24-1		Edward A. Brennan

24-2		M. Walter D’Alessio

24-3		Bruce DeMars

24-4		G. Fred DiBona, Jr.

24-5		Sue L. Gin

24-6		Edgar D. Jannotta

24-7		John M. Palms, Ph.D.

24-8		John W. Rogers, Jr.

24-9		Ronald Rubin

24-10		Richard L. Thomas

24-11		Nicholas DeBenedictis

24-12		Rosemarie B. Greco

99-1		Exelon Corporation’s Current Report on Form 8-K dated February 20, 2004, (File No. 1-16169).

286


Exhibit No.		Description
		Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Annual Report on Form 10-K for the year ended December 31, 2003 filed by the following officers for the following registrants:

31-1		Filed by John W. Rowe for Exelon Corporation

31-2		Filed by Robert S. Shapard for Exelon Corporation

31-3		Filed by John L. Skolds for Commonwealth Edison Company

31-4		Filed by J. Barry Mitchell for Commonwealth Edison Company

31-5		Filed by John L. Skolds for PECO Energy Company

31-6		Filed by J. Barry Mitchell for PECO Energy Company

31-7		Filed by Oliver D. Kingsley Jr. for Exelon Generation Company, LLC

31-8		Filed by J. Barry Mitchell for Exelon Generation Company, LLC

		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, 2003 filed by the following officers for the following registrants:

32-1		Filed by John W. Rowe for Exelon Corporation

32-2		Filed by Robert S. Shapard for Exelon Corporation

32-3		Filed by John L. Skolds for Commonwealth Edison Company

32-4		Filed by J. Barry Mitchell for Commonwealth Edison Company

32-5		Filed by John L. Skolds for PECO Energy Company

32-6		Filed by J. Barry Mitchell for PECO Energy Company

32-7		Filed by Oliver D. Kingsley Jr. for Exelon Generation Company, LLC

32-8		Filed by J. Barry Mitchell for Exelon Generation Company, LLC

*	Compensatory plan or arrangements in which directors or officers of the applicable registrant participate and which are not available to all employees.

287

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 20^th day of February, 2004.


EXELON CORPORATION

By:		/s/ JOHN W. ROWE
Name:		John W. Rowe
Title:		Chairman and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on the 20^th day of February, 2004.


Signature		Title
/s/ JOHN W. ROWE John W. Rowe		Chairman and Chief Executive Officer (Principal Executive Officer)

/s/ ROBERT S. SHAPARD Robert S. Shapard		Executive Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ MATTHEW F. HILZINGER Matthew F. Hilzinger		Vice President and Corporate Controller (Principal Accounting Officer)

This annual report has also been signed below by John W. Rowe, Attorney-in-Fact, on behalf of the following Directors on the date indicated:


EDWARD A. BRENNAN		ROSEMARIE B. GRECO
M. WALTER D’ALESSIO		EDGAR D. JANNOTTA
BRUCE DEMARS		JOHN M. PALMS, PH.D.
G. FRED DIBONA, JR.		JOHN W. ROGERS, JR.
SUE L. GIN		RONALD RUBIN
NICHOLAS DEBENEDICTIS		RICHARD L. THOMAS


By:	/s/ JOHN W. ROWE	February 20, 2004
Name:	John W. Rowe
Title:	Chairman and Chief Executive Officer

288

SIGNATURES


COMMONWEALTH EDISON COMPANY

By:		/s/ JOHN W. ROWE
Name:		John W. Rowe
Title:		Chairman and Chief Executive Officer, Exelon, and Chair and Director


Signature		Title
/s/ JOHN W. ROWE John W. Rowe		Chairman and Chief Executive Officer, Exelon, and Chair and Director

/s/ JOHN L. SKOLDS John L. Skolds		President, Exelon Energy Delivery (Principal Executive Officer)

/s/ J. BARRY MITCHELL J. Barry Mitchell		Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)

/s/ FRANK M. CLARK Frank M. Clark		President and Director

/s/ DUANE M. DESPARTE Duane M. DesParte		Vice President and Controller (Principal Accounting Officer)

/s/ OLIVER D. KINGSLEY JR. Oliver D. Kingsley Jr.		Director

/s/ ROBERT S. SHAPARD Robert S. Shapard		Director

/s/ S. GARY SNODGRASS S. Gary Snodgrass		Director

289

SIGNATURES


PECO ENERGY COMPANY

By:		/s/ JOHN W. ROWE
Name:		John W. Rowe
Title:		Chairman and Chief Executive Officer, Exelon, and Director


Signature		Title
/s/ JOHN W. ROWE John W. Rowe		Chairman and Chief Executive Officer, Exelon, and Director

/s/ JOHN L. SKOLDS John L. Skolds		President, Exelon Energy Delivery (Principal Executive Officer)

/s/ J. BARRY MITCHELL J. Barry Mitchell		Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)

/s/ DENIS P. O’BRIEN Denis P. O’Brien		President and Director

/s/ DUANE M. DESPARTE Duane M. DesParte		Vice President and Controller (Principal Accounting Officer)

/s/ OLIVER D. KINGSLEY JR. Oliver D. Kingsley Jr.		Director

/s/ ROBERT S. SHAPARD Robert S. Shapard		Director

290

SIGNATURES


EXELON GENERATION COMPANY, LLC

By:		/s/ JOHN W. ROWE
Name:		John W. Rowe
Title:		Chairman and Chief Executive Officer, Exelon


Signature		Title
/s/ JOHN W. ROWE John W. Rowe		Chairman and Chief Executive Officer, Exelon

/s/ OLIVER D. KINGSLEY JR. Oliver D. Kingsley Jr.		Chief Executive Officer and President (Principal Executive Officer)

/s/ J. BARRY MITCHELL J. Barry Mitchell		Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)

/s/ MATTHEW F. HILZINGER Matthew F. Hilzinger		Vice President and Corporate Controller, Exelon (Principal Accounting Officer)

291

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Exelon Generation 10-K2003 FY Annual report

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