Exelon Generation 10-K 2005 FY 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, 2005

OR

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

Commission File         Number	Name of Registrant; State of Incorporation; Address of Principal Executive Offices; and Telephone Number	IRS Employer Identification Number
1-16169	EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street—37th Floor P.O. Box 805379 Chicago, Illinois 60680-5379 (312) 394-7398	23-2990190
1-1839	COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321	36-0938600
000-16844	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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

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

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.  x

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Exelon Corporation	Yes  ¨	No  x
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, 2005, was as follows:

Exelon Corporation Common Stock, without par value	$34,404,316,038
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, 2006 was as follows:

Exelon Corporation Common Stock, without par value	667,233,091
Commonwealth Edison Company Common Stock, $12.50 par value	127,016,519
PECO Energy Company Common Stock, without par value	170,478,507
Exelon Generation Company, LLC	Not applicable

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
	Commonwealth Edison Company	6
	PECO Energy Company	6
	Exelon Generation Company, LLC	14
	Employees	25
	Environmental Regulation	26
	Security	34
	Other Subsidiaries of ComEd and PECO with Publicly Held Securities	34
	Managing the Risks in the Business	35
	Executive Officers of the Registrants	39
ITEM 1A.	RISK FACTORS	41
ITEM 1B.	UNRESOLVED STAFF COMMENTS	63
ITEM 2.	PROPERTIES	63
	Commonwealth Edison Company	63
	PECO Energy Company	63
	Exelon Generation Company, LLC	64
ITEM 3.	LEGAL PROCEEDINGS	66
	Exelon Corporation	66
	Commonwealth Edison Company	66
	PECO Energy Company	66
	Exelon Generation Company, LLC	66
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	70
PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	71
ITEM 6.	SELECTED FINANCIAL DATA	73
	Exelon Corporation	73
	Commonwealth Edison Company	75
	PECO Energy Company	76
	Exelon Generation Company, LLC	77
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION	78
	Exelon Corporation	79
	Commonwealth Edison Company	265
	PECO Energy Company	311
	Exelon Generation Company, LLC	351
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	149
	Exelon Corporation	149
	Commonwealth Edison Company	266
	PECO Energy Company	312
	Exelon Generation Company, LLC	359

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		Page No.
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	157
	Exelon Corporation	157
	Commonwealth Edison Company	267
	PECO Energy Company	313
	Exelon Generation Company, LLC	360
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	425
ITEM 9A.	CONTROLS AND PROCEDURES	425
	Exelon Corporation	425
	Commonwealth Edison Company	425
	PECO Energy Company	425
	Exelon Generation Company, LLC	425
ITEM 9B.	OTHER INFORMATION	425
	Exelon Corporation	425
PART III
ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT	426
	Exelon Corporation	426
	Commonwealth Edison Company	428
	PECO Energy Company	429
	Exelon Generation Company, LLC	430
ITEM 11.	EXECUTIVE COMPENSATION	431
	Exelon Corporation	431
	Commonwealth Edison Company	436
	PECO Energy Company	442
	Exelon Generation Company, LLC	447
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	466
	Exelon Corporation	466
	Commonwealth Edison Company	467
	PECO Energy Company	468
	Exelon Generation Company, LLC	469
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	469
	Exelon Corporation	469
	Commonwealth Edison Company	469
	PECO Energy Company	469
	Exelon Generation Company, LLC	469
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	470
	Exelon Corporation	470
	Commonwealth Edison Company	470
	PECO Energy Company	470
	Exelon Generation Company, LLC	470
PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	472
SIGNATURES		491
	Exelon Corporation	491
	Commonwealth Edison Company	492
	PECO Energy Company	493
	Exelon Generation Company, LLC	494

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FILING FORMAT

This combined Form 10-K is being filed separately 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

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 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation, (c) ITEM 8. Financial Statements and Supplementary Data: Exelon—Note 20, ComEd—Note 17, PECO—Note 15 and Generation—Note 17 and (d) 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 a registrant files with the SEC at the SEC’s public reference room at 100 F Street, N.E., 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. Information contained on Exelon’s website shall not be deemed incorporated into, or to be a part of, this Report.

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.comand 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.

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PART I

ITEM 1. BUSINESS

General

Exelon, a public utility holding company, operates through its principal subsidiaries—ComEd, PECO and Generation—as described below, each of which is treated as an operating segment by Exelon. In 2004, Exelon identified three operating segments—Energy Delivery (ComEd and PECO), Generation and Enterprises. Exelon sold or wound down substantially all components of Exelon Enterprises Company, LLC (Enterprises) in 2004 and 2003. As a result, Exelon ceased reporting Enterprises as a segment as of January 1, 2005. Additionally, Exelon concluded during the fourth quarter of 2005 that ComEd and PECO could no longer be aggregated as a combined Energy Delivery segment. As such, Exelon now presents three reportable segments: ComEd, PECO and Generation. Prior period presentation has been adjusted for comparative purposes. See Note 22 of Exelon’s Notes to Consolidated Financial Statements for further segment information.

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.

Proposed Merger with Public Service Enterprise Group Incorporated

On December 20, 2004, Exelon entered into an Agreement and Plan of Merger (Merger Agreement) with Public Service Enterprise Group Incorporated (PSEG), an exempt public utility holding company primarily located and serving customers in New Jersey, whereby PSEG will be merged with and into Exelon (Merger). PSEG shareholders approved the Merger on July 19, 2005. Exelon shareholders approved the issuance of Exelon shares pursuant to the Merger on July 22, 2005. Under the Merger Agreement, each share of PSEG common stock will be converted into 1.225 shares of Exelon common stock. As of December 31, 2005, PSEG’s market capitalization exceeded $16 billion. Additionally, at December 31, 2005, PSEG, on a consolidated basis, had approximately $13 billion of outstanding debt, which is currently anticipated to become part of Exelon’s consolidated debt.

In 2005, Exelon filed petitions or applications for approval or review of the Merger, or approval of matters related to the Merger, with various federal and state regulatory authorities, including the Federal Energy Regulatory Commission (FERC) under the Federal Power Act, the United States Department of Justice under the Hart Scott Rodino Antitrust Improvements Act of 1976, the Pennsylvania Public Utility Commission (PAPUC), the New Jersey Board of Public Utilities (NJBPU), the United States Nuclear Regulatory Commission (NRC), the New York Public Service Commission, the Connecticut Siting Council, the New Jersey Department of Environmental Protection (NJDEP) and the Public Utility Commission of Texas under the Texas Public Utility Regulatory Act. Various other state and Federal agencies and agencies of foreign countries have a role in reviewing various aspects of the transaction. ComEd filed a notice of the Merger with the Illinois Commerce Commission (ICC) and the ICC’s general counsel confirmed that its formal approval of the Merger is not required.

As of February 14, 2006, all material regulatory approvals or reviews necessary to complete the Merger have been completed with the exception of the approval from the NJBPU and the NRC and the review by the United States Department of Justice.

The FERC approved the Merger on June 30, 2005. Exelon and PSEG proposed in their application with the FERC, and FERC approved, a market concentration mitigation plan involving the divestiture of 4,000 MW of coal, mid-merit (or intermediate) and peaking generation in the PJM region and the ongoing auction of 2,600 MW of nuclear output and the interim mitigation of fossil generation

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pending divestiture. Exelon and PSEG also proposed to invest a total of $25 million in transmission improvements, which was included in the proposal that was accepted by FERC. The ultimate outcome of the market concentration mitigation is dependent upon various factors, including the market conditions and buyer interest at the time the generating units and the nuclear output are offered for sale. The results of these activities, therefore, are not assured, and could have a material impact on the results of operations and cash flows of Exelon and Generation if the sales price for the divested assets is different from management’s expectations. The FERC considered petitions for rehearing with respect to the order approving the Merger and affirmed its order on December 15, 2005. On January 6 and January 13, 2006, Philadelphia Gas Works/City of Philadelphia and subsidiaries of PPL Corporation, parties to the FERC proceeding, filed petitions for review of the FERC order in the United States Court of Appeals for the District of Columbia.

On January 27, 2006, the PAPUC approved the Merger and a partial settlement regarding PECO’s distribution and transmission rates through 2010 and other financial commitments of PECO related to the Merger. The settlement reflected the conclusion of a process involving the majority of PECO customer groups during which PECO’s cost data, return on equity and estimated Merger synergies were reviewed. The provisions of the PAPUC order and partial settlement are contingent upon the completion of the Merger. The PAPUC order and partial settlement require PECO to implement rate reductions aggregating $120 million during a four-year period and to cap its rates through the end of 2010. During the rate cap period, the PAPUC retains the right to lower PECO’s rates if they are found to be excessive, and PECO retains the right to seek rate increases if certain events (such as 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) occur. The partial settlement also provides substantial funding for alternative energy and environmental projects, economic development, and expanded outreach and assistance for low-income customers. PECO also made commitments for enhanced customer service and reliability, commitments for charitable giving and employment, and a pledge to maintain its Philadelphia headquarters for a period of time. The total of these funding commitments is approximately $44 million, of which $30 million will be expensed at the time the Merger is completed. By separate motion, the PAPUC also indicated its intent to initiate a separate investigation, to which PECO had agreed in the partial settlement, to examine issues related to a potential combination of Philadelphia Gas Works, which provides gas distribution service in the City of Philadelphia, into Exelon’s gas distribution businesses. This investigation will commence no earlier than 30 days after the close of the Merger. The outcome of this potential examination is uncertain. However, Exelon does not believe that the PAPUC has the authority to compel such a transaction if the two parties do not agree to terms through arms length negotiations.

On September 30, 2005, the administrative law judge in the proceeding before the NJBPU amended a prior prehearing order to modify the timetable for the regulatory approval process in New Jersey. The revised procedural schedule for the Merger review called for testimony to be filed from mid-November to mid-December and for hearings in January 2006. Under that revised schedule, the initial decision of the administrative law judge was expected in March 2006 and a final order from the full NJBPU was expected in May 2006. On January 25, 2006, the schedule for hearings was extended through March 27, 2006. On February 8, 2006, the administrative law judge approved a revised schedule calling for additional hearings on March 13, 14, 24 and 27, 2006. The dates originally scheduled for the administrative law judge’s initial decision and the final order of the full NJBPU will also be extended but no firm dates have been set. Settlement discussions in New Jersey began in December 2005 and are expected to resume after completion of hearings before the NJBPU. Exelon will attempt to reach a settlement that satisfactorily resolves issues and allows the Merger to close in the second quarter of 2006. However, in the absence of an earlier settlement, Exelon expects that the closing of the Merger will occur in the third quarter of 2006.

Various governmental, consumer and other parties have intervened in the proceedings before the NJBPU and other regulatory bodies. To facilitate approval of the Merger, Exelon may negotiate with

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these parties and may enter into settlement agreements. Orders resulting from the proceedings before the NJBPU and other regulatory bodies and settlements in connection with the proceedings could, for example, affect the extent to which Exelon and its subsidiaries may benefit from expected synergies following the Merger and could be materially different from what the Registrants expect in this and other respects, and could have a material impact on the financial condition, results of operations and cash flows of the Registrants if the Merger is completed.

The Merger Agreement contains certain termination rights for both Exelon and PSEG, and further provides that, upon termination of the Merger Agreement under specified circumstances, (i) Exelon may be required to pay PSEG a termination fee of $400 million plus PSEG’s transaction expenses up to $40 million or (ii) PSEG may be required to pay Exelon a termination fee of $400 million plus Exelon’s transaction expenses up to $40 million. Either Exelon or PSEG can terminate the Merger Agreement without penalty if the closing of the Merger does not occur on or before June 20, 2006; however, this termination right is not available to a party whose failure to fulfill any obligation under the Merger Agreement resulted in the failure to close the Merger by June 20, 2006.

Further information concerning the proposed Merger is included in the definitive joint proxy statement/prospectus filed by Exelon with the SEC on June 3, 2005 under SEC Rule 424(b)(3) (Registration No. 333-122704). For additional information related to the Merger, see ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Exelon—Executive Overview—Proposed Merger with PSEG and Note 3 of Exelon’s Notes to Consolidated Financial Statements. Except as otherwise specifically stated, any estimates of the Registrants for 2006 or thereafter disclosed in this Form 10-K do not reflect the effects of the Merger. In addition, PSEG and certain of its subsidiaries are reporting companies under the Securities Exchange Act of 1934, and their periodic reports and other filings are available on the web site maintained by the SEC athttp://www.sec.gov. The information contained in the SEC filings of PSEG and its subsidiaries shall not be deemed incorporated into, or to be a part of, this Report.

ComEd

ComEd’s energy delivery business consists of the purchase and regulated sale of electricity and distribution and transmission services to retail and wholesale customers in northern Illinois, including the City of Chicago.

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 440 South LaSalle Street, Chicago, Illinois 60605, and its telephone number is 312-394-4321.

PECO

PECO’s energy delivery business consists of the purchase and regulated sale of electricity and distribution and transmission services to retail customers in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated sale of natural gas and distribution services to retail customers in the Pennsylvania counties surrounding the City of Philadelphia.

PECO was incorporated in Pennsylvania in 1929. PECO’s principal executive offices are located at 2301 Market Street, Philadelphia, Pennsylvania 19103, 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 Generation, a 49.5% interest in two power stations in Mexico and the competitive retail sales business of Exelon Energy Company (Exelon Energy).

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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 businesses 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.

Upon completion of Exelon’s proposed merger with PSEG, the generation business of PSEG known as PSEG Power will be merged into Generation, which will be the surviving entity and PSEG Power will cease to exist. As of December 31, 2005, PSEG Power had total assets of $9 billion and $3 billion of outstanding debt which is currently anticipated to become part of Generation’s consolidated debt. In addition, as part of the FERC approval of the Merger, Generation has proposed a market concentration mitigation plan involving the divestiture of 4,000 MW of coal, mid-merit and peaking generation in the PJM region and the ongoing auction of 2,600 MW of nuclear output, and the interim mitigation of fossil generation pending divestiture.

Federal and State Regulation

Exelon is subject to Federal and state regulation. ComEd is a public utility under the Illinois Public Utilities Act subject to regulation by the ICC. PECO is a public utility under the Pennsylvania Public Utility Code subject to regulation by the PAPUC. ComEd, PECO and Generation are electric utilities under the Federal Power Act subject to regulation by the FERC. Specific operations of Exelon are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the NRC.

Exelon was a registered holding company and subject to a number of restrictions under the Public Utility Holding Company Act of 1935 (PUHCA) until the repeal of PUHCA, effective on February 8, 2006, pursuant to the Energy Policy Act of 2005 (the Energy Policy Act). Those restrictions involved financings, investments and affiliate transactions. Exelon had an order under PUHCA authorizing financing transactions for Exelon and the other Registrants within certain limits. With the repeal of PUHCA, the SEC’s financing jurisdiction under PUHCA for ComEd’s and PECO’s short-term financings and Generation’s financings reverted to FERC. Exelon’s financings are not subject to FERC jurisdiction. For additional information concerning regulatory approvals required for the Registrant’s financings, see ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources. Exelon also had an order under PUHCA authorizing development activities, the formation of new intermediate subsidiaries for internal corporate structuring, internal corporate reorganizations, and investments in certain non-United States (U.S.) energy-related subsidiaries. With the repeal of PUHCA, Exelon is no longer subject to these restrictions. PUHCA also limited the businesses in which Exelon could engage and the investments that Exelon could make, and required that Exelon’s utility subsidiaries constituted a single system that could be operated in an efficient, coordinated manner. With the repeal of PUHCA these restrictions are no longer applicable to Exelon.

Under the Energy Policy Act, FERC obtained additional jurisdiction for merger review and for the review of affiliate transactions, intercompany financings and cash management arrangements, certain internal corporate reorganizations, and certain holding company acquisitions of public utility and holding company securities. To the extent that the SEC’s jurisdiction under PUHCA preempted certain aspects of state regulation, the repeal of PUHCA enhanced the authority of states to regulate Exelon and its utility subsidiaries.

For additional information about Federal and state restrictions on Exelon and its subsidiaries, see ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Exelon.

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ComEd and PECO

Exelon’s regulated energy delivery operations consist of 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 and service, 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 ComEd’s 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, an area of about 225 square miles with an estimated population of three million. ComEd has approximately 3.7 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 2007 to 2061 and subsequent years. ComEd anticipates working with the appropriate agencies to extend or replace the franchise agreements prior to expiration.

PECO is engaged principally in the purchase, transmission, distribution and sale of electricity to residential, commercial and industrial customers in southeastern Pennsylvania and 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 PAPUC as to electric and gas rates and service, the issuances of certain securities and certain other aspects of PECO’s operations. PECO is also subject to regulation by the FERC as to transmission rates and certain other aspects of PECO’s business.

PECO’s retail service territory has an area of approximately 2,100 square miles and an estimated population of 3.8 million. PECO provides electric delivery service in an area of approximately 2,000 square miles, with a population of approximately 3.7 million, including 1.5 million in the City of Philadelphia. Natural gas service is supplied in an area of approximately 1,900 square miles in southeastern Pennsylvania adjacent to the City of Philadelphia, with a population of approximately 2.3 million. PECO delivers electricity to approximately 1.5 million customers and natural gas to approximately 472,000 customers.

PECO has the necessary authorizations to furnish regulated electric and gas service in the various municipalities or territories in which it now supplies such services. PECO’s authorizations consist of charter rights and certificates of public convenience issued by the PAPUC and/or “grandfather rights.” These rights are generally unlimited as to time and are generally exclusive from competition from other electric and gas utilities. In a few defined municipalities, PECO’s gas service territory authorizations overlap with that of another gas utility but PECO does not consider those situations as posing a material competitive or financial threat.

ComEd’s and PECO’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 occurred on August 21, 2003 and was 22,054 megawatts (MWs); its highest peak load during a winter season occurred on December 19, 2005 and was 16,081 MWs.PECO’s highest peak load occurred on July 27, 2005 and was 8,626 MWs; its highest peak load during a winter season occurred on December 20, 2004 and was 6,838 MWs.

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

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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 the supply of retail electricity while transmission and distribution service remains regulated. The legislation and related regulatory orders in both states allow customers to choose an alternative electric generation supplier; required rate reductions and imposed freezes or caps on rates during a transition period following the adoption of the legislation; and allow the collection of competitive transition charges (CTCs) from customers to recover a portion of the costs that might not otherwise be recovered in a competitive market (stranded costs) during the transition period.

Under Illinois and Pennsylvania legislation, ComEd and PECO are required to provide generation services to customers, except for certain large customers of ComEd, who do not or cannot choose an alternative supplier. Provider of last resort (POLR) obligations refer to the obligation of a utility to provide bundled services to those customers who do not take service from an alternative retail electric supplier or who choose to return 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 electricity demanded.

ComEd. All of ComEd’s customers are eligible to choose an alternative retail electric supplier and most non-residential customers can also elect the power purchase option (PPO) that allows the purchase of electricity from ComEd at market-based prices. As of December 31, 2005, one alternative electric supplier has approval from the ICC to serve residential customers in Illinois; however, no residential customers have actually selected an alternative electric supplier. At December 31, 2005, approximately 21,300 non-residential customers, representing approximately 33% of ComEd’s annual retail kilowatthour sales, had elected to purchase their electricity from an alternative electric supplier or had chosen the PPO. Customers who receive electricity from an alternative electric supplier and customers who have elected the PPO continue to pay a delivery charge to ComEd, which generally includes a CTC. Assuming ComEd is able to fully collect its costs of delivering electric service, there should be minimal long-term impact of customer choice on its results of operations. On January 24, 2006, the ICC unanimously approved the reverse-auction process as described below under “Illinois Procurement Filing,” with some modifications to enhance consumer protections and provide additional regulatory oversight. This approval, which is subject to rehearing and appeal, should provide ComEd with stability and greater certainty that it will be able to procure energy through the auction process and pass through the costs of that energy to ComEd’s customers beginning in 2007 through a transparent market mechanism in the reverse-auction process. ComEd petitioned for rehearing of the ICC decision on certain issues, but that petition was denied by the ICC on February 8, 2006. ComEd has offered to ease the impact of the expected increase in rates on residential customers, some or all of which could require regulatory or legislative approval to implement. See risk factor “ComEd may be required to sell energy at capped rates while buying energy at market rates, which are more volatile and potentially higher” in ITEM 1A. Risk Factors for further details.

In addition to retail competition for generation services, the Illinois legislation provided for phased residential base rate reductions totaling 20%, 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 utility may request a rate increase during the rate freeze period only when the return on equity falls beneath a defined floor 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 U.S. Treasury Long-Term Average Bond Rates (20 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

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amortization of regulatory assets. Under the Illinois statue, any impairment of goodwill has no impact on the determination of the cap on ComEd’s allowed equity return during the transition period. As a result of the Illinois legislation, at December 31, 2005, ComEd had a regulatory asset related to recoverable transition costs with an unamortized balance of $43 million, which will be fully recovered and amortized during 2006. ComEd has not triggered the earnings sharing provision through 2005 and does not currently expect to trigger the earnings sharing provision in 2006.

ComEd expects its capital expenditures will exceed depreciation on its rate base assets through at least 2006. The base rate freeze, coupled with other provisions of the Illinois restructuring law, generally precludes 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 remaining period of the rate freeze and until rate increases, post 2006, are approved authorizing a return of and on this new investment.

Illinois Procurement Filing.In 2004, the ICC initiated and conducted a workshop process to consider issues related to retail electric service in the post-transition period (i.e., post 2006). Issues addressed included utility wholesale electricity procurement methodology, rates, competition and utility service obligations and energy assistance programs. All interested parties were invited to participate. The end result was a report from the ICC to the Illinois General Assembly that was generally supportive of utilities competitively procuring electricity through a reverse-auction process with full recovery of the supply costs from retail customers. In the proposed reverse-auction model, qualified energy suppliers would compete in a transparent, fair and structured auction to provide electricity to the utilities and their customers; winning bidders would provide the electricity needed at the price determined by the auction’s results; and the utilities would make no profit on the electricity but would recover from customers the price of procurement. The ICC staff would oversee the entire process.

On February 25, 2005, ComEd filed with the ICC seeking regulatory approval of tariffs that implement the methodologies supported by the report, including a proposal consistent with the reverse-auction process described above (the Procurement Case). As requested by ComEd, the ICC initiated hearings on the matter. The Illinois Attorney General, Citizens’ Utility Board (CUB), Cook County State’s Attorney’s Office and the Environmental Law and Public Policy Center subsequently filed a motion to dismiss the proceeding arguing that customers whose retail service has not been declared competitive are entitled to cost-based rates for electricity and delivery and that the ICC lacked authority to approve rates based on the market value of electricity, as proposed by ComEd. On June 1, 2005, the administrative law judge denied the motion and, on July 13, 2005, the ICC denied the appeal. On December 5, 2005, the administrative law judge issued a proposed order that recommended that the ICC approve the competitive procurement process similar to the ComEd proposal. The administrative law judge reaffirmed an earlier ruling that the ICC has legal authority under the Public Utility Act to approve an auction process and the resulting rates. The proposed order also increased the regulatory oversight of the process.

On January 24, 2006, the ICC, by a unanimous vote, approved a reverse-auction competitive bidding process for procurement of power by ComEd for the time period after 2006. The procurement process is similar to the process described in the Procurement Case and the administrative law judge’s order described above, with some modifications to enhance consumer protection. The auction will be administered by an independent auction manager, with oversight by the ICC staff. The first auction is scheduled to take place during the fall of 2006, at which time ComEd’s entire load will be up for bid. To mitigate the effects of changes in future prices, the load will be staggered in three-year contracts. To further mitigate the impact on its residential customers of transitioning to this process, ComEd has offered to develop a “cap and deferral” proposal to ease the impact of the expected increase in rates on residential customers, some or all of which could require regulatory or legislative approval to implement. A cap and deferral proposal, generally speaking, would limit the procurement costs that ComEd could pass through to its customers for a specified period of time and allow ComEd to collect any unrecovered procurement costs in later years.

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Several parties that were opposed to the Procurement Case have indicated that they will petition the ICC for rehearing and will challenge the ICC decision in court. ComEd also petitioned for rehearing of the ICC decision on certain issues, but that petition was denied by the ICC on February 8, 2006. It is also possible that interested parties could introduce legislation in Illinois in an attempt to modify the procurement process or the rates that ComEd may charge consumers for the power ComEd purchases to meet the needs of consumers. The Illinois General Assembly has held hearings concerning generation procurement after 2006, and it may take action on this issue.

On September 1, 2005, the Illinois Attorney General, the Cook County State’s Attorney, CUB and the Environmental Law and Public Policy Center filed a two-count complaint in the Chancery Division of the Circuit Court of Cook County against the ICC and the individual ICC commissioners (the Procurement Litigation). The Procurement Litigation sought to block the ICC from approving the Procurement Case on the theory that the ICC lacked the authority to approve the rates because not all of the services that will be provided under the Procurement Case have been declared competitive and do not qualify for market-based rates. The legal argument underlying the Procurement Litigation is substantially similar to the legal argument that was presented to the administrative law judge, and to the ICC on appeal, and rejected by both, in the third quarter of 2005. ComEd intervened in the Procurement Litigation to deny the allegations in the complaint and sought a determination that the ICC has appropriate legal authority to approve the proposed electricity procurement process pending before the ICC in the Procurement Case. ComEd moved for summary judgment in the litigation, and the ICC moved to dismiss one claim in the litigation and for summary judgment on the other claim. A hearing on the motions was held on December 14, 2005 and the court issued a written order on January 20, 2006 denying the relief sought by the plaintiffs and dismissing the case with prejudice.

On October 17, 2005, ComEd and Generation filed an application with the FERC seeking approval that the proposed Illinois auction process meets FERC principles and that if Generation is selected as a winning bidder in the Illinois auction, the standard agreements under which Generation would sell energy, capacity and ancillary services to ComEd would be acceptable to the FERC. On December 16, 2005, the FERC issued an order granting both requests.

In November 2005, ComEd announced several actions intended to affirm the fact that ComEd is an independent entity, separate and distinct from its parent Exelon, and to strengthen ComEd’s ability to successfully manage some potentially challenging financial and strategic issues as Illinois continues its transition to restructuring after 2006. The actions include the election of a new board of directors of ComEd and selection of senior officers. The senior officers have responsibilities solely for ComEd.

The ICC, in its Order approving the Procurement Case, also ordered its Staff to “present orders initiating three separate rulemakings regarding demand response programs, energy efficiency programs and renewable energy resources to the Commission within thirty (30) days of the entry of this Order.” ComEd intends to participate in any such rulemakings.

Illinois Rate Case. On August 31, 2005, ComEd filed a rate case with the ICC, which seeks, among other things, to allocate the costs of delivering electricity and to adjust ComEd’s rates for delivering electricity effective January 2, 2007 (Rate Case). Several intervenors in the Rate Case, including the ICC staff and the Illinois Attorney General, have suggested, and provided testimony, that ComEd’s rates should actually be reduced. The commodity component of ComEd’s rates will be established by the reverse-auction process in accordance with the ICC order in the Procurement Case, assuming the ICC order on this matter is upheld upon appeal. The results of the Rate Case are not expected to be known until at least the third quarter of 2006.

ComEd cannot predict the results of the Rate Case before the ICC or whether the Illinois General Assembly might take action that could have a material impact on the outcome of the regulatory process. However, if the price at which ComEd is allowed to sell electricity beginning in 2007 is below

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ComEd’s cost to procure and deliver electricity, there may be material adverse consequences to ComEd and, possibly, Exelon. Exelon and ComEd believe that these potential material adverse consequences could include, but may not be limited to, loss of ComEd’s investment grade credit rating and a possible reduction in the other Registrants’ credit ratings, limited or lost access for ComEd to credit markets to finance operations and capital investment, and loss of ComEd’s capacity to enter into bilateral long-term electricity procurement contracts, which would likely force ComEd to procure electricity at more volatile and potentially higher prices in the spot market. Moreover, to the extent ComEd is not permitted to recover its costs, ComEd’s ability to maintain and improve service may be diminished and its ability to maintain reliability may be impaired. In the nearer term, these prospects could have adverse effects on ComEd’s liquidity if vendors reduce credit or shorten payment terms or if ComEd’s financing alternatives become more limited and significantly less flexible. ComEd also cannot predict the long-term impact of customer choice for electricity supply on its results of operations.

The Illinois restructuring legislation also provided for the collection of a CTC from customers who choose to purchase electricity from an alternative electric supplier or elect the PPO during the transition period which extends through 2006. The CTC is applied on a cents per kWh basis and considers the revenue that would have been collected from a customer under tariffed rates as 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.

ComEd’s market value energy 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 alternative electric supplier or the PPO. The credit has the effect of reducing ComEd’s CTCs to customers. The current annual market price adjustment reflects forward, rather than historical, market prices for electricity and allows customers to lock in current levels of CTCs for the remainder of the regulatory transition period ending in 2006.

In 2005 and 2004, ComEd collected $105 million and $169 million in CTC revenues, respectively. ComEd estimates that CTC revenue will range from $35 million to $50 million in 2006.

The Illinois restructuring legislation provides that an electric utility, such as ComEd, will be liable for actual damages suffered by customers in the event of a continuous electricity 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. During the years 2005, 2004 and 2003, ComEd did not have any outages that triggered the reimbursement requirement.

ComEd has a purchase power agreement (PPA) with Generation under which ComEd obtains substantially all of its electric supply from Generation through 2006. Prices for this electricity vary depending on the time of day and month of delivery.

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, 2005, approximately 1% of PECO’s residential load, 13% of its small commercial and industrial load and 1% of its large commercial and industrial load were purchasing

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generation service from alternative generation suppliers. Customers who purchase electricity from an alternative electric 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 and transmission 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 2005, 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 PAPUC’s approval of the merger among PECO, Unicom Corporation (Unicom), the former parent company of ComEd, and Exelon (PECO / Unicom Merger), PECO agreed to $200 million in aggregate rate reductions for all customers over the period January 1, 2002 through December 31, 2005 and extended the rate cap on distribution and transmission rates through December 31, 2006.

Partial Settlement before the PAPUC. On January 27, 2006, the PAPUC approved the Merger and a partial settlement regarding PECO’s distribution and transmission rates through 2010 and other financial commitments of PECO related to the Merger. The settlement reflected the conclusion of a process involving the majority of PECO customer groups during which PECO’s cost data, return on equity and estimated Merger synergies were reviewed. The provisions of the PAPUC order and partial settlement are contingent upon the completion of the Merger. The PAPUC order and partial settlement require PECO to implement rate reductions aggregating $120 million during a four-year period and to cap its rates through the end of 2010. During the rate cap period, the PAPUC retains the right to lower PECO’s rates if they are found to be excessive, and PECO retains the right to seek rate increases if certain events (such as 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) occur. The partial settlement also provides substantial funding for alternative energy and environmental projects, economic development, and expanded outreach and assistance for low-income customers. PECO also made commitments for enhanced customer service and reliability, commitments for charitable giving and employment, and a pledge to maintain its Philadelphia headquarters for a period of time. The total of these funding commitments is approximately $44 million, of which $30 million will be expensed at the time the Merger is completed. By separate motion, the PAPUC also indicated its intent to initiate a separate investigation, to which PECO had agreed in the partial settlement, to examine issues related to a potential combination of Philadelphia Gas Works, which provides gas distribution service in the City of Philadelphia, into Exelon’s gas distribution businesses. This investigation will commence no earlier than 30 days after the close of the Merger. The outcome of this potential examination is uncertain. However, Exelon does not believe that the PAPUC has the authority to compel such a transaction if the two parties do not agree to terms through arms length negotiations. See General—Proposed Merger with Public Service Enterprise Group Incorporated above and Note 4 of Exelon’s Notes to Consolidated Financial Statements for further discussion.

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 the customer purchases electricity from the utility or an alternative electric 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

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were awarded, except where continued operation is no longer cost efficient because of the transition to a competitive market.

As mentioned above, PECO has been authorized by the PAPUC 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, 2005, the unamortized balance of PECO’s stranded costs, or CTC regulatory asset, was $3.5 billion. The following table shows PECO’s allowed recovery of stranded costs, and amortization of the associated regulatory asset, for the years 2006 through 2010 as authorized by the PAPUC 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.

Year (in millions)	Estimated CTC Revenue		Estimated Stranded Cost Amortization
2006	$	903	$	550
2007		910		619
2008		917		697
2009		924		783
2010		932		880

Under the Competition Act, licensed entities, including alternative electric suppliers, may act as agents to provide a single bill and provide associated billing and collection services to retail customers located in PECO’s retail electric service territory. In that event, the alternative supplier or other third party replaces the customer as the obligor with respect to the customer’s bill and PECO generally has no right to collect such receivable from the customer. Third-party billing would change PECO’s customer profile (and risk of non-payment by customers) by replacing multiple customers with the entity providing third-party billing for those customers. PAPUC-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.

PECO has a PPA with Generation under which PECO obtains substantially all of its electric supply from Generation through 2010. The price for this electricity is essentially equal to the energy revenues earned from customers as specified by PECO’s 1998 settlement of its restructuring case mandated by the Competition Act. Subsequent to 2010, PECO expects to procure all of its supply from market sources, which could include Generation.

Regulations applicable to all Pennsylvania electric utilities’ POLR obligations are being developed by the PAPUC. PECO will continue to monitor the developments of these regulations.

In November 2004, Pennsylvania adopted Act 213, the Alternative Energy Portfolio Standards Act of 2004. For more information, see “Environmental Regulation—Renewable and Alternative Energy Portfolio Standards” below.

Transmission Services

ComEd and PECO provide 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,

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ComEd and PECO, 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, ComEd and PECO 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’s amendments to the Standards of Conduct regulation under Order No. 2004 do not detrimentally affect Exelon’s business.

PJM Interconnection, LLC (PJM) is the independent system operator and the FERC-approved regional transmission organization (RTO) for the Mid-Atlantic and Midwest regions 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 controls through central dispatch the day-to-day operations of the bulk power system of the PJM region. ComEd and PECO are members of PJM and provide regional transmission service pursuant to the PJM tariff. ComEd, PECO and the other transmission owners in PJM have turned over control of their transmission facilities to PJM and their transmission systems are currently under the dispatch control of PJM. 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.

The FERC has attempted to expand the development of regional markets, which has generated substantial opposition from some state regulators and other governmental bodies. In addition, efforts to develop an RTO have been abandoned in certain regions. Notwithstanding these difficulties, the Midwest Independent System Operator, Inc. (MISO), has been certified as an RTO by FERC. MISO is attempting to develop central generation dispatch and transmission operations across the Midwestern United States, contiguous to PJM’s footprint. The FERC has ordered the elimination of rate barriers and protocol differences between MISO and PJM. Exelon supports the development of RTOs and implementation of standard market protocols.

In November 2004, the FERC issued two orders authorizing ComEd and PECO to recover amounts as a result of the elimination of through and out (T&O) rates for transmission service scheduled out of or across their respective transmission systems and ending within pre-expansion PJM or MISO territories. T&O rates were terminated pursuant to FERC orders effective December 1, 2004. The new rates, known as Seams Elimination Charge/Cost Adjustment/Assignment (SECA), are collected from load-serving entities within PJM and MISO over a transitional period from December 1, 2004 through March 31, 2006, subject to refund, surcharge and hearing. As load-serving entities, ComEd and PECO are also required to pay SECA rates based on the benefits they receive from the elimination of T&O rates of other transmission owners within PJM and MISO. On June 16, 2005, FERC issued an order setting a hearing to address SECA cost recovery issues, and consolidated that proceeding with a proceeding to address long-term transmission rate design.

Amounts collected under the SECA rates are subject to refund and surcharge and the ultimate outcome of the proceeding establishing SECA rates is uncertain.

Gas

PECO’s gas sales and gas transportation revenues are derived pursuant to rates regulated by the PAPUC. 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.

PECO’s gas customers have the right to choose their gas suppliers or to purchase their gas supply from PECO at cost. Approximately 32% of PECO’s current total yearly throughput is provided by gas suppliers other than PECO and is related primarily to the supply of PECO’s large commercial

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and industrial customers. Gas transportation service provided to customers by PECO 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 eight years. These purchases are delivered under several long-term firm transportation contracts. PECO’s aggregate annual firm supply under these firm transportation contracts is 44.6 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 33% of PECO’s 2005-2006 heating season planned supplies.

Construction Budget

ComEd’s and PECO’s businesses are capital intensive and require significant investments in energy transmission and distribution facilities, and in other internal infrastructure projects. The following table shows the most recent estimate of capital expenditures for plant additions and improvements for ComEd and PECO for 2006:

(in millions)	ComEd		PECO
Transmission and distribution	$	870	$	215
Gas		—		65
Other		55		50
Total	$	925	$	330

Approximately 50% of the projected 2006 capital expenditures at ComEd and PECO are for continuing efforts to maintain and improve the reliability of their transmission and distribution systems. 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 and the competitive retail sales business of Exelon Energy, which became part of Generation effective as of January 1, 2004.

At December 31, 2005, Generation owned generation assets with a net capacity of 25,099 MWs, including 16,856 MWs of nuclear capacity. In addition, Generation controlled another 8,191 MWs of capacity through long-term contracts.

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. In addition, Power Team markets energy in the wholesale bilateral and spot markets.

Exelon Energy provides retail electric and gas services as an unregulated retail energy supplier in Illinois, Michigan and Ohio. Exelon Energy’s 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 service customers with higher volumes so as to manage costs.

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Generating Resources

At December 31, 2005, the generating resources of Generation consisted of the following:

Type of Capacity	MWs
Owned generation assets (a)
Nuclear	16,856
Fossil (b, c)	6,636
Hydroelectric	1,607
Owned generation assets	25,099
Long-term contracts (d)	8,191
TEG and TEP (e)	230
Total generating resources	33,520

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

(b) Includes the total capacity of the Southeast Chicago Energy Project.

(c) Excludes 195 MWs related to the capacity of Handley Units 1 and 2 and Mountain Creek Unit 3. These units were removed from service in 2005.

(d) Contracts ranging in duration of up to 25 years.

(e) Generation, through its investments in Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (TEP), owns a 49.5% interest in two facilities in Mexico, each with a capacity of 230 MWs.

The owned generating resources of Generation are located in the Midwest region (approximately 45% of capacity), the Mid-Atlantic region (approximately 44% of capacity), the Southern region (approximately 9%), and the Northeast region (approximately 2% of capacity). The 8,191 MWs of capacity that Generation controls through long-term contracts are in the Midwest, Southeast and South Central regions.

On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe Energies, Inc. (Sithe). Specifically, subsidiaries of Generation closed on the acquisition of Reservoir Capital Group’s 50% interest in Sithe and the sale of 100% of Sithe to Dynegy, Inc. (Dynegy). Prior to closing on the sale to Dynegy, subsidiaries of Generation received approximately $65 million in cash distributions from Sithe. As a result of the sale, Exelon and Generation deconsolidated approximately $820 million of debt from their balance sheets and were released from approximately $125 million of credit support. See Note 3 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the sale of Sithe.

The sale of Sithe did not include Tamuin International Inc., (formerly Sithe International, Inc.), which was sold to a subsidiary of Generation on October 13, 2004. Tamuin International, Inc., through its subsidiaries, has a 49.5% interest in two Mexican business trusts that own the TEG and TEP power stations, two 230 MW petcoke-fired generating facilities in Tamuín, Mexico.

Nuclear Facilities

Generation has ownership interests in eleven nuclear generating stations currently in service, consisting of 19 units with 16,856 MWs of capacity. For additional information, see ITEM 2. Properties. Generation’s nuclear generating stations are operated by Generation, with the exception of the two units at the Salem Generating Station (Salem), which are operated by PSEG Nuclear, LLC (PSEG Nuclear), an indirect, wholly owned subsidiary of PSEG. AmerGen, wholly owned by Generation, operates the Clinton Nuclear Power Station, the Three Mile Island (TMI) Unit No. 1 and the Oyster Creek Generating Station (Oyster Creek).

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Effective January 17, 2005, Generation began overseeing daily plant operations at Salem and Hope Creek nuclear generating stations through an Operating Services Contract (OSC) with PSEG Nuclear. Hope Creek is a nuclear generating station wholly owned by PSEG Nuclear. Under the OSC, PSEG Nuclear remains as the license holder with exclusive legal authority to operate and maintain the plants, retains responsibility for management oversight and has full authority with respect to the marketing of its share of the output from the facilities.

In 2005, 71% of Generation’s electric supply was generated from the nuclear generating facilities. During 2005 and 2004, the nuclear generating facilities operated by Generation achieved a 93.5% capacity factor.

During 2004, both Quad Cities’ units operated only intermittently at Extended Power Uprate (EPU) generation levels due to performance issues with their steam dryers. As of the third quarter of 2005, both of the Quad Cities’ units returned to EPU generation levels after extensive testing and load verification on new replacement steam dryers was completed.

Near the end of 2005, the generation levels of both Quad Cities’ units were again reduced to pre-EPU generation levels to address vibration–related equipment issues not directly related to the steam dryers. The units will be brought back to full EPU generation levels after all issues are addressed to ensure safe and reliable operations at the EPU output levels which is expected to occur in 2006.

In 2004, Generation joined a consortium of eleven companies, NuStart Energy Development, LLC (NuStart), which was formed for the purpose of seeking a license to build a new nuclear facility under the NRC’s new permitting process. As of December 31, 2005, Generation’s investment in NuStart was $2 million.

Regulation of Nuclear Power Generation. 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 and 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 and/or increased operating costs of nuclear generating units.

NRC reactor oversight results, as of December 31, 2005, indicate that the performance indicators for the nuclear plants operated by Generation are all in the highest performance band.

Licenses. Generation has 40-year operating licenses from the NRC for each of its nuclear units and has received 20-year operating license renewals for Peach Bottom Units 2 and 3, Dresden Units 2 and 3, and Quad Cities Units 1 and 2. In December 2004, the NRC issued an order that will permit Oyster Creek to operate beyond its license expiration in April 2009 if the NRC has not completed reviewing the application for renewal. The application for Oyster Creek’s license renewal was filed July 22, 2005, in compliance with this order. Generation is currently evaluating its other nuclear units for possible license renewal. The operating license renewal process takes approximately four to five years from the commencement of the project until completion of the NRC’s review. The NRC review process takes approximately two years from the docketing of an application. Each requested license renewal is expected to be for 20 years beyond the current license expiration. Depreciation provisions are based on the estimated useful lives of the stations, which assume the renewal of the operating licenses for all of Generation’s operating nuclear generating stations. In the first quarter of 2005, Generation applied the same depreciation estimated useful life assumption to its ownership share in the Salem Generating Station.

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The following table summarizes the current operating license expiration dates for Generation’s nuclear facilities in service:

Station	Unit	In-Service Date(a)	Current License Expiration
Braidwood	1	1988	2026
	2	1988	2027
Byron	1	1985	2024
	2	1987	2026
Clinton	1	1987	2026
Dresden	2	1970	2029
	3	1971	2031
LaSalle	1	1984	2022
	2	1984	2023
Limerick	1	1986	2024
	2	1990	2029
Oyster Creek	1	1969	2009
Peach Bottom	2	1974	2033
	3	1974	2034
Quad Cities	1	1973	2032
	2	1973	2032
Salem	1	1977	2016
	2	1981	2020
Three Mile Island	1	1974	2014

(a) Denotes year in which nuclear unit began commercial operations.

Nuclear Waste Disposal. There are no facilities for the reprocessing or permanent disposal of spent nuclear fuel (SNF) currently in operation in the United States, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by nuclear generating facilities in on-site storage pools and, in the case of Peach Bottom, Oyster Creek, Dresden and Quad Cities, 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 respective plant. Generation is developing dry cask storage facilities, as necessary, to support operations.

As of December 31, 2005, Generation had approximately 44,792 SNF assemblies (10,402 tons) stored on site in SNF pools or dry cask storage. On-site dry cask storage in concert with on-site storage pools will be 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 reserve (a)
Dresden	Dry cask storage in operation
Quad Cities	Dry cask storage in operation
Byron	2011
LaSalle	2012
Braidwood	2013
Clinton(b)	2006
Peach Bottom	Dry cask storage in operation
Limerick	2009
Oyster Creek	Dry cask storage in operation
Three Mile Island	Life of plant storage capable in SNF pool
Salem	2011

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(a) The date for loss of full core reserve identifies when the on-site storage pool will no longer have sufficient space to discharge a full complement of fuel from the reactor core.

(b) A modification to the on-site storage pool is in progress to increase the amount of SNF that can be stored in the pool. This will move the date for loss of full core reserve at Clinton out to approximately 2012.

Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy (DOE) is responsible for the development of a repository 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 Contracts) to provide for disposal of SNF from its nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation pays the DOE one mill ($.001) per kWh of net nuclear generation for the cost of SNF disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts 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 2012. 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. See Note 13 of Exelon’s Notes to Consolidated Financial Statements and Note 13 of Generation’s Notes to Consolidated Financial Statements for additional information regarding spent fuel storage claims and issues.

During 2004, Exelon and the U.S. Department of Justice, in close consultation with the DOE, reached a settlement of a suit originally commenced by ComEd in 1998. Under the settlement, the government has agreed to reimburse Exelon for costs associated with storage of spent fuel at Generation’s nuclear stations pending DOE’s fulfilment of its obligations to take possession of SNF. Under the settlement agreement, Generation received $80 million in gross reimbursements for storage costs already incurred ($53 million net, after considering amounts due from Exelon to co-owners of certain nuclear stations). In 2005, Generation received $58 million in gross reimbursements for storage costs incurred between October 1, 2003 and June 30, 2005, ($35 million net, after considering amounts due from Exelon to co-owners and previous owners of certain nuclear stations). Generation plans to submit annual reimbursement requests for costs associated with the storage of spent nuclear fuel. In all cases, reimbursement requests will be made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF.

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to pay the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, just prior to the first delivery of SNF to the DOE. As of December 31, 2005, the unfunded liability for the one-time fee with interest (which has been assumed by Generation) was $906 million. Interest accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect, for calculation of the interest accrual at December 31, 2005, was 3.983%. The outstanding one-time fee obligation for the Oyster Creek and TMI units remains with the former owners. The Clinton Unit has no outstanding obligation.

As a by-product of their operations, nuclear generating units produce low-level radioactive waste (LLRW). LLRW is accumulated at each generating station and permanently disposed of at Federally licensed disposal facilities. The Federal Low-Level Radioactive Waste Policy Act of 1980 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.

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Generation has temporary on-site storage capacity at its nuclear generation stations for limited amounts of LLRW and has been shipping its LLRW to disposal facilities in South Carolina and Utah. With a limited number of available LLRW disposal facilities, Generation anticipates the possibility of continuing difficulties in disposing of LLRW. Generation continues to pursue 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 $31 million in 2005 ($27 million net after considering amounts collected from co-owners of certain nuclear stations).

Nuclear Insurance.The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. The Price-Anderson Act was extended to December 31, 2025 under the terms of the Energy Policy Act. As of December 31, 2005, the current limit was $10.76 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 $10.46 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. The maximum assessment for all nuclear operators per reactor per incident (including a 5% surcharge) is $100.6 million, payable at no more than $15 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.

See “Nuclear Insurance” within Note 20 of Exelon’s Notes to Consolidated Financial Statements and Note 17 of Generation’s Notes to Consolidated Financial Statements for a description of nuclear-related insurance coverage.

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 or are within the policy deductible for its insured losses. 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. As more fully described below, both ComEd and PECO are currently collecting amounts from customers, which are ultimately remitted to the trust funds maintained by Generation that will be used to decommission nuclear facilities. The AmerGen facilities are not covered by ComEd, PECO or any other rate recovery of decommissioning funding from customers. Decommissioning expenditures are expected to occur primarily after the plants are retired. Based on current operating licenses and anticipated license renewals, decommissioning expenditures for plants in operation are currently estimated to begin in 2029.

Under the ICC order, ComEd is permitted to recover up to $73 million per year through 2006 from customers to decommission former ComEd nuclear plants. Collections are limited based on the ratio of electricity purchased by ComEd to the total amount generated from those units. In 2005, decommissioning revenues collected from ComEd customers totaled approximately $68 million and are expected to be approximately the same in 2006. Under the current ICC order, ComEd is not permitted to collect amounts for decommissioning subsequent to 2006. Nuclear decommissioning costs associated with the nuclear generating stations formerly owned by PECO continue to be

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recovered currently through rates charged by PECO to customers. Amounts recovered, currently $33 million per year, are remitted to Generation as allowed by the PAPUC. The PAPUC will allow PECO to collect from customers and remit to Generation, annually, through the operating life of the plants.

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. See the risk factor “Generation’s financial performance may be negatively affected by liabilities arising from its ownership and operation of nuclear facilities” for further detail. Generation has reviewed the GAO’s report and believes 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.

Generation believes that the amounts currently being collected from ComEd and PECO, coupled with Generation’s nuclear decommissioning trust funds and the expected investment earnings thereon will be sufficient to fully fund Generation’s decommissioning obligations. AmerGen maintains decommissioning trust funds for each of its plants in accordance with NRC regulations. Generation believes that amounts in these trust funds together with expected investment earnings thereon will be sufficient to fully fund AmerGen’s decommissioning obligations.

See Critical Accounting Policies and Estimates within ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Generation for a further discussion of nuclear decommissioning.

Zion, a two-unit nuclear generation station, Peach Bottom Unit 1 and Dresden Unit 1 have permanently ceased power generation. SNF at Zion and Dresden Unit 1 is currently being stored in on-site storage pools and dry cask storage, respectively, until a permanent repository under the NWPA is completed. All of Peach Bottom Unit 1’s SNF has been moved off site. Generation has recorded a liability totaling $766 million at December 31, 2005, which represents the estimated cost of decommissioning Zion, Peach Bottom Unit 1 and Dresden Unit 1 in current year dollars. Certain decommissioning costs are currently being incurred; however, the majority of decommissioning expenditures are expected to occur primarily after 2013, 2033 and 2031 for Zion, Peach Bottom Unit 1 and Dresden Unit 1, respectively.

Fossil and Hydroelectric Facilities

Generation operates various fossil and hydroelectric facilities and maintains ownership interest in several other facilities such as LaPorte, Keystone, Conemaugh and Wyman, which are operated by third parties. In 2005, approximately 7% of Generation’s electric supply 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. For additional information regarding Generation’s electric generating facilities, see ITEM 2. Properties—Generation.

Licenses. Fossil generation plants are generally not licensed and, therefore, the decision on when to retire plants is, fundamentally, a commercial one. Hydroelectric plants are licensed by the FERC. The Muddy Run and Conowingo facilities have licenses that expire in September 2014. Generation is in the process of performing pre-application analyses and anticipates filing a Notice of Intent to renew the licenses in 2009 pursuant to FERC regulations.

Insurance.Generation does not purchase business interruption insurance for its wholly owned fossil and hydroelectric operations. For its other types of insured losses, Generation is self-insured to

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the extent that losses are within the policy deductible or 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 and cash flows. For information regarding property insurance, see ITEM 2. Properties—Generation.

Long-Term Contracts

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

Seller	Location	Expiration	Capacity (MWs)
Kincaid Generation, LLC	Kincaid, Illinois	2011	1,108
Tenaska Georgia Partners, LP	Franklin, Georgia	2030	925
Tenaska Frontier, Ltd	Shiro, Texas	2020	830
Green Country Energy, LLC	Jenks, Oklahoma	2022	795
Elwood Energy, LLC	Elwood, Illinois	2012	772
Lincoln Generating Facility, LLC	Manhattan, Illinois	2011	664
Reliant Energy Aurora, LP	Aurora, Illinois	2008	600
Others (a)	Various	2006 to 2023	2,497
Total			8,191

(a) Includes long-term capacity contracts with nine counterparties.

Federal Power Act

The Federal Power Act gives the FERC exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to the FERC’s jurisdiction are required to file rate schedules with the FERC with respect to wholesale sales and transmission of electricity. Transmission 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 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 power 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 subsequently determined that Generation or any of its affiliates violated the terms and conditions of its tariff or the Federal Power Act. The FERC is also authorized to order refunds if it finds that the market-based rates are not just and reasonable under the Federal Power Act.

For a number of years, the FERC has been encouraging the voluntary formation of RTOs, such as PJM, to provide transmission service across multiple transmission systems. The intended benefits of establishing these entities include managing transmission congestion, developing larger wholesale markets for energy and capacity, and the elimination or reduction of transmission charges imposed by successive transmission systems when wholesale generators cross several transmission systems to deliver capacity.

To date, PJM, the Midwest ISO, and ISO New England, have been approved as RTOs. Because of some states’ opposition to imposition of centralized energy and capacity markets, the new FERC Chairman has been seeking to enhance the independence of transmission operations without the overlay of centralized markets.

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Exelon supports the development of RTOs and implementation of standard market protocols but cannot predict their success or whether they will lead to the development of the envisioned large, successful wholesale markets. The FERC issued a final rule establishing standardized generator interconnection policies and procedures. Under this interconnection policy generators will benefit from not having to deal on a case-by-case basis with different and sometimes inconsistent requirements of different transmission providers.

In 2004, the FERC implemented market power tests for suppliers to qualify to sell power at market-based rates. These new tests, the market share test and the pivotal supplier test, must both be passed by Generation, or market power mitigation must be imposed for Generation to continue to make sales of capacity and energy in the wholesale market at market-based rates. The FERC allows the relevant geographic market to include a RTO’s footprint, and Generation used an expanded PJM footprint as the relevant market.

On July 5, 2005, the FERC approved Generation’s continued authority to charge market-based rates for wholesale sales of electricity, including to its affiliates ComEd and PECO. In the same order, the FERC stated that Generation had failed to address the affiliate abuse prong of the FERC’s market-based rate eligibility test and used that statement as the basis for instituting a proceeding under the provision of the Federal Power Act, Section 206 and establishing a refund effective date of July 26, 2005 in the event that the FERC ultimately found that Generation did not, in fact, qualify for market-based rates. The FERC ordered Generation to make a compliance filing within 30 days of the order addressing the affiliate abuse and reciprocal dealing prong of the market-based rate test.

On August 4, 2005, Generation filed a Petition for Rehearing asking the FERC to rescind the part of its market-based rate order that had opened a Section 206 investigation into the issue of affiliate abuse and had established a refund effective date. Generation had addressed the affiliate abuse issue in its original November 2003 triennial update filing. The September 2004 filing had addressed only the new generation market power issue, as the FERC had directed. In the August 2005 filing, Generation noted the original reference in the September 2004 filing to the fact that the FERC had previously found that circumstances existed that guarded against affiliate abuse. Generation further noted that as of both the September 2004 and August 2005 filings there had been no change in the circumstances cited in the FERC’s original order granting authority to Generation to sell electricity at market-based rates. Generation’s pleading asked the FERC to either grant the rehearing request or to consider the August filing to be the required compliance filing.

The July 2005 market-based rate order also directed Exelon to make compliance filings within 30 days of the order amending the market-based rate tariffs of Exelon’s various subsidiaries to include prohibiting sales of electricity to Public Service Electric and Gas Company (PSE&G), PSEG’s regulated utility, unless specific authority were sought for such sales under Section 203 of the Federal Power Act. These compliance filings were made in accordance with the Order.

The Energy Policy Act of 2005. The Energy Policy Act, which was signed into law on August 8, 2005, implements several significant changes intended to improve electric reliability, promote investment in electric facilities, streamline electric regulation, improve wholesale competition, address problems identified in the western energy crisis and Enron collapse, promote fuel diversity and cleaner fuel sources, and promote greater efficiency in electric generation, delivery and use.

The Energy Policy Act, through amendment of the Federal Power Act, also transfers to the FERC certain additional authority. The FERC obtains new authority to review the acquisition or merger of generating facilities, along with the responsibility to address more explicitly cross-subsidization issues in these situations. The FERC now has the authority to approve siting of electric transmission facilities located in national interest electric transmission corridors if states cannot or will not act in a timely manner to approve siting. The Energy Policy Act also creates a self-regulating electric reliability organization with the FERC oversight to enforce reliability rules.

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Fuel

The following table shows sources of electric supply in gigawatthours (GWhs) for 2005 and estimated for 2006:

	Source of Electric Supply
	2005	2006 (Est.)
Nuclear units	137,936	137,832
Purchases—non-trading portfolio	42,623	50,098
Fossil and hydroelectric units	13,778	13,891
Total supply	194,337	201,821

The fuel costs for nuclear generation are substantially less than for fossil-fuel generation. Consequently, nuclear generation is generally the most cost-effective way for Generation to meet its commitment to supply the requirements of ComEd and PECO, some of Exelon Energy’s requirements, 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 2008. Generation’s contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2008. All of Generation’s enrichment requirements have been contracted through 2010. Contracts for fuel fabrication have been obtained through 2008. Generation does not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment or fabrication services for its nuclear units.

Generation obtains approximately 40% 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.

Natural gas requirements for operating stations are 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 so that in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable market pricing.

Generation uses financial instruments to mitigate price risk associated with commodity price exposures. Generation also hedges forward price risk with both over-the-counter and exchange-traded instruments.

Power Team

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

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maintain a net positive supply of energy and capacity, through ownership of generation assets and purchase 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 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. Power Team may buy power to meet the energy demand of its customers, including ComEd and PECO. These purchases may be made for more than the energy demanded by Power Team’s customers. Power Team then sells this open position, along with capacity not used to meet customer demand, in the wholesale energy 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.

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 2006 for its energy marketing portfolio is approximately 88%. This hedge ratio represents the percentage of forecasted aggregate annual generation supply that is committed to firm sales, including sales to ComEd’s and PECO’s retail load. The hedge ratio is not fixed and will vary from time to time depending upon market conditions, demand and volatility. During summer peak demand periods, the hedge ratio declines to assure Generation’s commitment to meet demand in ComEd’s and PECO’s regions. 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 only a small portion of Power Team’s efforts. 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.

At December 31, 2005, Generation’s long-term commitments relating to the purchase and sale of energy, capacity and transmission rights from and to unaffiliated utilities and others were as follows:

(in millions)	Net Capacity Purchases (a)		Power Only Sales		Power Only Purchases from Non-Affiliates		Transmission Rights Purchases (b)
2006	$	616	$	2,783	$	1,508	$	7
2007		527		947		491		3
2008		460		80		194		—
2009		434		18		194		—
2010		436		19		194		—
Thereafter		3,391		—		355		—
Total	$	5,864	$	3,847	$	2,936	$	10

(a) Net capacity purchases include tolling agreements that are accounted for as operating leases. Amounts presented in the commitments represent Generation’s expected payments under these arrangements at December 31, 2005. Expected payments include certain capacity charges which are conditional on plant availability.

(b) Transmission rights purchases include estimated commitments in 2006 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, as amended, with ComEd under which Generation has agreed to supply all of ComEd’s load requirements through 2006. Under the ComEd PPA, prices for energy vary depending upon the time of day and month of

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delivery. Subsequent to 2006, ComEd expects to procure all of its supply from market sources, which could include Generation. Additionally, 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 electricity to PECO from the transferred generation assets, assigned PPAs and other market sources. Subsequent to 2010, PECO expects to procure all of its electricity from market sources, which could include Generation.

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 2006 are as follows:

(in millions)
Production plant	$	604
Nuclear fuel		511
Total	$	1,115

Employees

As of December 31, 2005, Exelon and its subsidiaries had approximately 17,200 employees in the following companies:

ComEd	5,500
PECO	2,000
Generation	7,700
Other(a)	2,000
Total	17,200

(a) Other includes shared services and Enterprises employees.

Approximately 5,400 employees, including 3,800 employees of ComEd, 1,600 employees of Generation and 100 employees of Exelon Business Services Company (BSC), are covered by collective bargaining agreements (CBAs) with Local 15 of the International Brotherhood of Electrical Workers (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 September 30, 2007. The CBA for ComEd and BSC expires on September 30, 2008. The Clinton, Oyster Creek and TMI CBAs expire on December 15, 2010, January 31, 2010 and February 28, 2009, respectively. Exelon Power, an operating unit of Generation, has an agreement with Utility Workers of America (UWA) Local 369, which expires on January 31, 2007 and covers approximately 50 employees. In addition, Exelon Power has an agreement with IBEW Local 614, which expires on January 31, 2008 and covers approximately 200 employees.

In addition to IBEW Local 15, IBEW Local 614 and the four IBEW locals covering the AmerGen facilities, approximately 40 Generation employees are represented by the Utility Workers Union of America.

During 2004, two elections were held at PECO which resulted in union representation for approximately 1,100 employees in the Philadelphia service territory. PECO and IBEW Local 614 began negotiations for an initial agreement in 2005. No agreement has been finalized to date.

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The employees of the Limerick and Peach Bottom nuclear stations are not represented by a union. On May 5, 2005, a majority of these employees elected not to be represented by the IBEW 614. The union has contested the election, which is currently under review by the National Labor Relations Board.

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 United States Environmental Protection Agency (EPA) administers certain Federal statutes relating to such matters, as do various interstate and local agencies. 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, the New Jersey Department of Environmental Protection has jurisdiction in New Jersey 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.

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 renewals of such permits while operating under an administrative extension.

In July 2004, the EPA issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. This rule establishes national requirements for reducing the adverse environmental impacts from the entrainment and impingement of aquatic organisms at existing power plants. The rule identifies particular standards of performance with respect to entrainment and impingement and requires each facility to monitor and validate this performance in future years. The requirements will be implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g. cooling towers) are potentially most affected. Those facilities are Clinton, Cromby, Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, New Boston, Oyster Creek, Peach Bottom, Quad Cities and Salem. Generation is currently evaluating compliance options at its affected plants. At this time, Generation cannot estimate the effect that compliance with the Phase II rule requirements will have on the operation of its generating facilities and its future results of operations, financial condition and cash flows. There are many factors to be considered and evaluated to determine how Generation will comply with the Phase II rule requirements and the extent to which such compliance may result in financial and operational impacts. The considerations and evaluations include, but are not limited to obtaining clarifying interpretations of the requirements from state regulators, resolving outstanding litigation proceedings concerning the requirements, completing studies to establish biological baselines for each facility, and performing environmental and economic cost benefit evaluations of the potential compliance alternatives in accordance with the requirements.

In a pre-draft permit dated May 13, 2005 and a draft permit issued on July 19, 2005, as part of the pending NPDES permit renewal process for Oyster Creek, the NJDEP preliminarily determined that closed-cycle cooling and environmental restoration are the only viable compliance options for

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Section 316(b) compliance at Oyster Creek. AmerGen has not made a determination regarding how it will demonstrate compliance with the Section 316(b) regulations, but believes that other compliance options under the final Phase II rule are viable and will be analyzed as part of the plant’s comprehensive demonstration study. If application of the Section 316(b) regulations requires the retrofitting of Oyster Creek’s cooling water intake structure or system, or extensive wetlands restoration, this could result in material costs of compliance and increased depreciation expense. In addition, the amount of the costs required to retrofit Oyster Creek may negatively impact Generation’s decision to renew the operating license.

In June 2001, the NJDEP issued a renewed NDPES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised PSEG in a letter dated July 12, 2004 that it strongly recommended reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG submitted an application for a renewal of the permit on February 1, 2006. In the permit renewal application, PSEG analyzed closed-cycle cooling and other options and demonstrated that the continuation of the Estuary Enhancement Program, an extensive environmental restoration program at Salem, is the best technology to meet the Section 316(b) requirements. If application of the Section 316(b) regulations ultimately requires the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, Exelon’s share of the total cost of the retrofit and any resulting interim replacement power would likely be in excess of $500 million and could result in increased depreciation expense related to the retrofit investment.

On December 16, 2005, the Illinois Environmental Protection Agency (Illinois EPA) issued a Violation Notice to Generation alleging that the company had violated state groundwater standards as a result of historical discharges of liquid tritium from a line at the Braidwood Nuclear Generating Station. In November 2005, Generation discovered that spills from the line in 1998 and 2000 have resulted in a tritium plume in groundwater that is both on and off the plant site. Levels of tritium in portions of the plume are in excess of the Illinois EPA groundwater standard. Levels in portions of the plume also exceed the Illinois EPA and Federal limits for drinking water. However, samples from drinking water wells on property adjacent to the plant have shown that, with one exception, tritium levels in these wells are below levels that naturally occur. The tritium level in one drinking water well is elevated above levels that naturally occur, but is significantly below the state and federal drinking water standards, and Generation believes that this level poses no threat to human health. Generation has suspended liquid tritium discharges into the affected pipeline, and is investigating the causes of the releases to ensure that necessary corrective actions are taken to prevent another occurrence. Generation has analyzed the various remediation options for the groundwater, and submitted an initial report to the Illinois EPA on February 2, 2006. The Illinois EPA will determine the required remediation and whether a civil penalty will be assessed against Generation. Generation has notified 14 potentially affected adjacent property owners that, upon sale of their property, it will reimburse them for any diminution in property value caused by the release, and has purchased the property of one adjacent owner. As of December 31, 2005, Generation, recorded a reserve of $7 million (pre-tax) for this matter, which Generation deems adequate to cover the costs of remediation and potential related corrective measures.

Also, as a result of intensified monitoring and inspection efforts in 2006, Exelon detected a small underground tritium leak at the Dresden Generating Station and tritium concentrations in standing water within concrete vaults at the Byron Generating Station. Neither of these discharges occurred outside the property lines of the plant, nor does Exelon believe either of these matters poses health or safety threats to employees or to the public. In response to the detection of tritium in water samples taken at the aforementioned nuclear generating stations, Exelon has launched an initiative across its ten-station nuclear fleet to systematically assess systems that handle tritium and take the necessary actions to minimize the risk of inadvertent discharge of tritium to the environment. The assessments

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will take place in 2006 and will cover pipes, pumps, valves, tanks and other pieces of equipment that carry tritiated water in and around the plants. At this time, Exelon cannot estimate the costs that may be incurred in connection with tritium assessment initiatives or possible remediation efforts of the Dresden and Byron matters.

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 (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 25%. On July 19, 1995, the EPA issued a proposed plan for remediation of the site, which involves removal of contaminated soil,

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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 conducted the remedial design and submitted to the EPA the revised final design on January 15, 2003.

A final settlement agreement has been reached between the EPA, the PRP group and the former owners and operators of the site. The final design estimates for the cost to implement the remedial action range from $14 million to $17 million. This amount does not include the PRP group’s future legal and technical expenses, which are not expected to be material. The settlement amount also does not include any damages for natural resource damages that the EPA or state environmental agencies may seek to obtain in the future, and at this time PECO cannot predict with reasonable certainty the likelihood that such damages will be sought or the amount of any such damages. Based on the amounts already contributed by the PRP group, it is expected that payments from the former owners and operators of the site will be sufficient to pay for the remedial action. Should any additional payments be required from the PRP group, PECO’s share would be 25%.

The parties lodged the settlement with the U.S. District Court for the Eastern District of Pennsylvania (the “District Court”). Prior to the dismissal of the litigation, the District Court must approve the settlement, after an opportunity for public comment. Following publication of a notice of the settlement and a public meeting on the settlement, the Delaware River Basin Commission, the PDEP, and the NJDEP filed petitions to intervene in the litigation. Following a conference with the judge, the proposed intervenors filed a motion with the District Court to withdraw their petitions to intervene. On January 26, 2006 the Court granted the motion and dismissed the petitions. It is expected that the District Court will approve the Consent Decrees, thereby settling the case.

Cotter Corporation

The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. Cotter is alleged to have disposed of approximately 39,000 tons of soils mixed with 8,700 tons of leached barium sulfate at the site. Cotter, along with three other companies identified by the EPA as PRPs, has submitted a draft feasibility study addressing options for remediation of the site. The PRPs are also engaged in discussions with the State of Missouri and the EPA. The estimated costs of the anticipated remediation strategy for the site ranges up to $22 million. Once a remedy is selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. On February 18, 2000, ComEd sold Cotter to an unaffiliated third party. As part of the sale, ComEd agreed to indemnify Cotter for liability from the West Lake Landfill and the litigation described under ITEM 3. Litigation—Generation. 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.

MGP Sites

MGPs manufactured gas in Illinois and Pennsylvania from approximately 1850 to 1950. ComEd and PECO generally did not operate MGPs as corporate entities but did, however, acquire MGP sites as part of the absorption of smaller utilities. To date, ComEd has identified 42 former MGP sites for which it may be liable for remediation. Of these 42 sites, the Illinois Environmental Protection Agency has approved the clean-up of six sites. Similarly, PECO has identified 27 sites where former MGP activities may have resulted in site contamination. Of these 27 sites, the PDEP has approved the clean-up of nine 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, 2005, ComEd and

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PECO had accrued $48 million (discounted) and $41 million (discounted), respectively, for investigation and remediation of these MGP sites that currently can be reasonably estimated. ComEd and PECO believe that they could incur additional liabilities with respect to MGP sites, which cannot be reasonably estimated at this time. In 2005, PECO finalized settlement agreements with all of its insurers of PECO’s claims for recovery of remediation costs associated with environmental remediation projects and received $14 million of insurance proceeds. In 2005, ComEd finalized a settlement agreement with its insurance carrier in the amount of approximately $4 million for costs associated with environmental remediation projects. 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 (CAA) 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 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 (“NO_x SIP Call” regulations) adopted by the 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 started May 31, 2004. Texas is not covered by the EPA’s NOx SIP Call regulations. The EPA’s NOx SIP Call regulations currently require 19 eastern states to reduce summertime NO_x emissions.

Generation has evaluated options for compliance with the NO_x SIP Call 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. Generation’s NO_x compliance program is 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 Handley and Mountain Creek 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, and that was fully implemented on May 1, 2005. Additionally, beginning May 1, 2003, these plants were required to comply with the Emission Banking and Trading of Allowances (EBTA) program established by the State of Texas 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, installed Selective Catalytic Reduction technology on Handley Units 3, 4 and 5, as well as Mountain Creek Unit 8. Additionally, Induced Flue Gas Recirculation Technology was installed on Mountain Creek Units 6 and 7.

During March 2005, the EPA finalized several new rulemakings designed to reduce powerplant emissions of SO₂, NO_x and mercury. In its Clean Air Interstate Rule (CAIR), the EPA established new

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annual (applicable in 23 eastern states) and ozone season (applicable in 25 eastern states) NO_xemission caps that are scheduled to take effect in 2009. Further, CAIR requires an additional reduction of SO₂ emissions in 23 eastern states starting in 2010. CAIR also requires an additional reduction of NO_x and SO₂ emissions in 2015. The new SO₂ and NO_x emission caps finalized by the EPA are substantially below current industry emission levels. In a separate rulemaking also issued in March 2005, the Clean Air Mercury Rule (CAMR), the EPA also finalized a national program to cap mercury emissions from coal-fired generating units starting in 2010, with a second reduction in the mercury emission cap level scheduled for 2018. In its final CAMR, the EPA determined that it would not regulate nickel emissions from oil-fired power plants, as it had considered in its proposed rulemaking. Generation is currently evaluating its compliance options with regard to the final CAIR and CAMR regulations. Final compliance decisions will be affected by a number of factors, including, but not limited to, the final form of state implementing regulations that are currently under development, as well as the resolution of legal challenges initiated by certain parties (not including Exelon) in the Federal courts regarding the final CAIR and CAMR regulations. Legal challenges to a related final rulemaking, also published in March 2005, in which the EPA rescinded its December 2000 regulatory finding on hazardous air pollutants from electric utility steam generating units, may also have an effect on Generation’s final compliance decisions to the extent such litigation has an effect on the CAMR. During late 2005, the EPA also agreed to reconsider and take additional public comment regarding certain aspects of its final CAIR and CAMR rulemakings. The EPA will consider these comments in early 2006.

Finally, a number of states in which Generation operates are considering establishing state and/or regional requirements for NO_x, SO₂ and mercury emissions that could require larger emission reductions, on shorter time schedules, than are required by the EPA’s CAMR and CAIR. For example, the PDEP has initiated a state-specific mercury rulemaking process that may result in a Pennsylvania mercury regulation that exceeds the requirements of CAMR. Pennsylvania is also participating with other Ozone Transport Commission (OTC) states in the northeast, in the development of a “CAIR-Plus” program for the northeast states that could require NO_x, SO₂ and mercury reductions in excess of the EPA’s requirements.

In addition to Federal and state regulatory activities, several legislative proposals regarding the control of emissions of air pollutants from a variety of sources, including generating plants, have been proposed in the United States Congress. For example, several multi-pollutant bills have been introduced that would reduce generating plant emissions of NO_x, SO₂, mercury and carbon dioxide starting late this decade and into the next decade.

At this time, Exelon can provide no assurance that new legislative and regulatory proposals, if adopted, will not have a significant effect on Generation’s operations and cash flows.

Global Climate Change

The United States is currently not a party to the United Nations’ Kyoto Protocol (Protocol) that became effective for signatories on February 16, 2005. The Protocol process generally requires developed countries to cap greenhouse gas (GHG) emissions at certain levels during the 2008-2012 time period. Although it is not a signatory to the Protocol, the United States may adopt a national, mandatory GHG program at some point in the future. In addition, on August 24, 2005, the Regional Greenhouse Gas Initiative (RGGI), a cooperative effort by Northeastern and Mid-Atlantic states to reduce carbon dioxide (CO₂) emissions, one of the greenhouse gases, released a program proposal. Central to this proposal is the implementation of a multi-state cap-and-trade program with a market-based emissions trading system. The proposed program would apply to electric power generators of 25MW or greater in the participating states. On December 20, 2005, seven of the nine RGGI states signed a Memorandum of Understanding (MOU) under which they committed to develop a detailed model rule during 2006 to be used by individual states to adopt the RGGI requirements outlined in the MOU. The RGGI MOU is an agreement to stabilize aggregate carbon dioxide emissions from power plants in participating states at current levels from 2009 to 2015. Further, a 10 percent reduction from current levels would be required to be phased in starting in 2016 such that by 2019

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there would be a 10 percent reduction in participating state power plant emissions. States participating in the RGGI MOU include Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York and Vermont. Maryland and Pennsylvania have been observers of the process. Generation owns a small amount of peaking and intermediate generating capacity in the RGGI region. At this time, Exelon is unable to predict the potential impacts of any future mandatory governmental GHG legislative or regulatory requirements on its businesses.

In the absence of a mandatory national program, Exelon has joined the U.S. EPA Climate Leaders Partnership (Climate Leader). As a Climate Leader partner, Exelon is conducting an annual inventory of its GHG emissions and annually reporting its GHG emissions and progress toward achieving GHG reductions. In addition, on May 6, 2005, Exelon announced that it has established a voluntary goal to reduce its GHG emissions by eight percent from 2001 levels by the end of 2008. The eight percent reduction goal represents a decrease of an estimated 1.3 million metric tons of GHG emissions. Exelon will incorporate recognition of GHG emissions and their potential cost into its business analyses as a means to promote internal investment in climate-reducing activities. Exelon believes that its planned greenhouse gas management efforts, including increased use of renewable energy, its current energy efficiency initiatives and its efforts in the areas of carbon sequestration, will allow it to achieve this goal. The anticipated cost of achieving the voluntary GHG emissions reduction goal will not have a material effect on Exelon’s future results of operations, financial condition and cash flows.

As an integrated electric and gas utility, approximately 90% of Exelon’s GHG emissions result from Generation’s combustion of fossil fuels to generate electricity, with CO₂ representing the largest quantity of GHG emitted. The majority of Generation’s owned generation is comprised of nuclear and hydroelectric assets that have negligible GHG emissions compared to fossil-based electric generation alternatives. By virtue of Generation’s significant investment in these low carbon intensity assets, Generation’s owned-generation portfolio CO₂emission intensity, or rate of CO₂ emitted per kilowatt-hour of electricity generated, is among the lowest in the industry.

Renewable and Alternative Energy Portfolio Standards

Approximately 26 states have adopted some form of renewable portfolio standard (RPS) legislation. On November 30, 2004, Pennsylvania adopted Act 213, the Alternative Energy Portfolio Standards Act of 2004 (AEPS Act). The AEPS Act mandates that two years after its effective date (February 28, 2005) at least 1.5% of electric energy sold by an electric distribution company or electric generation supplier to Pennsylvania retail electric customers must come from Tier I alternative energy resources. The Tier I requirement escalates to 8.0% by the 15^th year after the effective date of the AEPS Act. The AEPS Act also establishes a Tier II requirement of 4.2% for years one through four. This requirement grows to 10.0% by the 15^th year. In March 2005, the PAPUC issued its first implementation order related to the AEPS. In this order, the PAPUC established a schedule for Tier I and Tier II resources with year one covering the period June 1, 2006 through May 31, 2007. During year one, compliance with the Tier I and Tier II requirements begins on February 28, 2007.

Tier I resources include: solar photovoltaic energy, wind power, low-impact hydro, geothermal energy, biologically derived methane gas, fuel cells, biomass energy and coal mine methane. A small percentage of the Tier I requirements must be met specifically by solar photovoltaic technologies (starting at 0.0013% in year 1 and escalating to 0.25% by year 10). Tier II resources include: waste coal, distributed generation systems, demand side management, large-scale hydropower, municipal solid waste and several other technologies.

The AEPS Act provides an exemption for electric distribution companies that have not reached the end of their cost recovery period during which competitive transition charges or intangible transition charges are being recovered. At the conclusion of the electric distribution company’s cost recovery period, this exemption no longer applies and compliance by the electric distribution company is

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required at the percentages in effect at that time. PECO’s cost recovery period expires December 31, 2010.

In the first year after the end of an electric distribution company’s cost recovery period, the AEPS Act provides for cost recovery on a full and current basis pursuant to an automatic energy adjustment charge as a cost of generation supply. The banking of credits from voluntary sales of Tier I and Tier II sources sold by electric distribution companies prior to the expiration of their specific cost recovery periods is also allowed under the AEPS Act. Voluntary sales under the AEPS Act are deferred as a regulatory asset by the electric distribution company and are fully recoverable at the end of the cost recovery period, also pursuant to an automatic energy adjustment clause as a cost of generation supply.

While Generation is not directly affected by the AEPS Act from a compliance perspective, increased deployment of renewable and alternative energy resources within the regional power pool resulting from the AEPS Act will have some influence on regional energy markets.

It is anticipated that, during 2006 and 2007, the PAPUC will promulgate regulations or policy statements concerning the registration, banking, and cost recovery associated with alternative energy generation and associated credits. Once these regulations and the aforementioned regulations being promulgated for PECO’s POLR role become effective, PECO will determine whether those regulations present any risk for PECO’s recovery of purchase power costs associated with alternative energy and other POLR power purchases post-2010.

During 2005, the Governor of Illinois proposed a voluntary Sustainable Energy Plan, which was subsequently endorsed by the ICC. Under the terms of the Plan, that includes both renewable and efficiency/demand response components, retail suppliers, including ComEd, would obtain renewable energy products equivalent to 2% of the energy supplied to customers in 2007, increasing by 1% annually to an ultimate target of 8% by 2013, with 75% of the targeted amounts to come from wind sources. ComEd’s response to this program will be made as part of its overall post 2006 strategy. Resolution of several outstanding legal and regulatory issues with respect to post-transition procurement and cost recovery is required. See “Retail Electric Services—ComEd” above for further detail on these outstanding legal and regulatory issues.

In addition to state level activity, RPS legislation has been considered and may be considered again in the future by the United States Congress. Also, states that currently do not have RPS requirements may determine to adopt such legislation in the future.

Exelon is currently evaluating the potential impacts of RPS legislation on its businesses.

Costs of Environmental Remediation

At December 31, 2005, Exelon, ComEd, PECO and Generation had accrued $128 million, $54 million, $47 million and $27 million, respectively, for various environmental investigation and remediation. These costs include approximately $48 million at ComEd and $41 million at PECO for former MGP sites as described above. Exelon, ComEd, PECO and Generation 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 Exelon, ComEd, PECO and Generation, environmental agencies or others, or whether all such costs will be recoverable through rates or from third parties.

The budgets for expenditures in 2006 at Exelon, ComEd, PECO and Generation for compliance with environmental requirements total approximately $16 million, $6 million, $7 million and $3 million, respectively. In addition, ComEd, PECO and Generation may be required to make significant additional expenditures not presently determinable.

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Security

Exelon does not fully know the impact that future terrorist attacks may have on the electric and gas industry in general and on Exelon in particular. Exelon has implemented security measures to safeguard its employees and critical operations and is actively participating in industry initiatives to identify methods to maintain the reliability of Exelon’s energy production and delivery systems. Additionally, the energy industry is working with governmental agencies to coordinate emergency plans and to address vulnerabilities of critical infrastructures to maintain the reliability of the country’s energy systems. These measures have resulted in and are expected to continue to result in increased costs, but will provide increased assurances for Exelon’s ability to maintain critical operations.

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.

Other Subsidiaries of ComEd and PECO with Publicly Held Securities

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 U.S. Bank Trust, National Association, as Delaware trustee, and two individual trustees appointed by ComEd. ComEd Funding LLC, a special purpose Delaware limited liability company, was organized on July 21, 1998. 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 Trust II, a Delaware statutory trust, was formed by ComEd on November 20, 1996. ComEd Financing Trust II was created solely for the purpose of issuing and selling preferred and common securities. On January 24, 1997, ComEd Financing Trust II issued $150 million of trust preferred securities, carrying an annual distribution rate of 8.50%, which are mandatorily redeemable on January 15, 2027. ComEd is the sole owner of all of the common securities of ComEd Financing Trust II. The sole assets of ComEd Financing Trust II are $155 million principal amount of 8.50% subordinated deferrable interest debentures due January 15, 2027, issued by ComEd.

ComEd Financing Trust III, a Delaware statutory trust, was formed by ComEd on September 5, 2002. ComEd Financing Trust III was created for the sole purpose of issuing and selling preferred and common securities. On March 17, 2003, ComEd Financing Trust III issued $200 million of trust preferred securities, carrying an annual distribution rate of 6.35%, which are mandatorily redeemable on March 15, 2033. ComEd is the sole owner of all of the common securities of ComEd Financing Trust III. 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.

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 US Bank Trust, National Association, as issuer trustee, and two

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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 from customers transition charges sufficient to pay the principal and interest on the transition bonds.

PECO Energy Capital Corp., a wholly owned subsidiary of PECO (PECC), is the sole general partner of PECO Energy Capital, L.P., a Delaware limited partnership (PEC L.P.). PEC L.P. 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 PEC L.P. The only revenues of PEC L.P. are interest on the Subordinated Debentures. All of the operating expenses of PEC L.P. are paid by PECC. As of December 31, 2005, PEC L.P. held $81 million aggregate principal amount of the Subordinated Debentures.

PECO Energy Capital Trust III (PECO Trust III), a Delaware statutory trust, was formed by PECO in April 1998. PECO Trust III was created solely for the purpose of issuing $78 million trust receipts (Trust III Receipts) each representing a 7.38% Cumulative Preferred Security, Series D (Series D Preferred Securities) of PEC L.P. PEC L.P. is the sponsor of PECO Trust III. As of December 31, 2005, PECO Trust III had outstanding 78,105 Trust III Receipts. At December 31, 2005, the assets of PECO Trust III consisted solely of 78,105 Series D Preferred Securities with an aggregate stated liquidation preference of $81 million.

PECO Energy Capital Trust IV (PECO Trust IV), a Delaware statutory trust, was formed by PECO in May 2003. PECO Trust IV was created solely for the purpose of issuing and selling preferred and common securities. On June 17, 2003, PECO Trust IV issued $100 million of trust preferred securities, carrying an annual distribution rate of 5.75%, which are mandatorily redeemable on June 15, 2033. PECO is the sole owner of all of the common securities of the PECO Trust IV. The sole assets of PECO Trust IV are $103 million principal amount of 5.75% subordinated debentures issued by PECO.

See Note 1 of Exelon’s Notes to Consolidated Financial Statements for additional information.

Managing the Risks in the Business

Exelon, ComEd, PECO and Generation have considered the business challenges facing them and have adopted certain risk management activities. The Registrants recognize that their risk management activities address only certain of the challenges facing the Registrants and that those activities may not be effective in all circumstances. A discussion of the risks to which the Registrants’ businesses are subject and the potential consequences of those risks are contained in ITEM 1A. Risk Factors. On a continuing basis, the Registrants evaluate the challenges of their businesses and their ability to identify and mitigate these risks.

ComEd and PECO

Rate and equity return limitations. While ComEd and PECO continue to make significant capital expenditures to maintain and improve the reliability of each respective transmission and distribution system and to support new business and customer growth, ComEd and PECO also continue to work more efficiently to lower operating and maintenance costs. Exelon believes that ComEd, subject to the resolution of regulatory issues—see Retail Electric Services above, and PECO will continue to provide a significant and steady source of earnings and cash flows over the next several years.

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Post-transition rates.In order to address post-transition uncertainty, ComEd has made two different regulatory filings to establish the rates to be charged to customers effective January 2, 2007. The first filing relates to ComEd’s ability to procure electricity supply. The second filing established the delivery service rates that will be charged to customers. Through these proceedings ComEd is working with the ICC, consumer advocates and business community leadership to facilitate the development of a competitive electricity market while providing system reliability and safety. ComEd is promoting constructs that will move it towards transparent and liquid markets to allow for electricity procurement that will be deemed prudent, provide consumers assurance of equitable pricing and ensure adequate cost recoverability.

On January 24, 2006, the ICC, by a unanimous vote, approved a reverse-auction competitive bidding process for procurement of power by ComEd for the time period after 2006. The procurement process is similar to the process described in the Procurement Case with some modifications to enhance consumer protection. The auction will be administered by an independent auction manager, with oversight by the ICC staff. The first auction is scheduled to take place during the fall of 2006, at which time ComEd’s entire load will be up for bid. To mitigate the effects of changes in future prices, the load will be staggered in three-year contracts. To further mitigate the impact on its residential customers of transitioning to this process, ComEd has offered to develop a “cap and deferral” proposal to ease the impact of the expected increase in rates on residential customers, some or all of which could require regulatory or legislative approval to implement. A cap and deferral proposal, generally speaking, would limit the procurement costs that ComEd could pass through to its customers for a specified period of time and allow ComEd to collect any unrecovered procurement costs in later years.

Several parties that were opposed to the Procurement Case have indicated that they will petition the ICC for rehearing and will challenge the ICC decision in court. ComEd also petitioned for rehearing of the ICC decision on certain issues, but that petition was denied by the ICC on February 8, 2006. It is also possible that interested parties could introduce legislation in Illinois in an attempt to modify the procurement process or the rates that ComEd may charge consumers for the power ComEd purchases to meet the needs of consumers. The Illinois General Assembly has held hearings concerning generation procurement after 2006, and it may take action on this issue.

While PECO has made no regulatory filings to date to revise its transmission and distribution rates, PECO will 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. PECO will strive to ensure that future rate structures recognize the substantial improvements PECO has made, and will continue to make, in its transmission and distribution systems. PECO will also work to ensure that its post-2010 rates are adequate to cover its costs of obtaining electricity from its suppliers, which could include Generation, for the costs associated with procuring full requirements power given PECO’s POLR obligations. As in the past, by working together with interested parties, PECO believes it can successfully meet these objectives and obtain fair recovery of its costs for providing service to its customers after the transition periods.

Power supply risks. To effectively manage its obligation to provide power to meet its customers’ demand, ComEd and PECO have established full-requirements, power supply agreements with Generation which reduce exposure to the volatility of customer demand and market prices through 2006 for ComEd and through 2010 for PECO. Market prices relative to ComEd’s and PECO’s regulated rates still influence whether retail customers purchase electricity from ComEd, PECO or from an alternative electric supplier.

Beyond 2006 for ComEd, assuming the auction process that was approved by the ICC for the procurement of electricity remains in effect, ComEd would be allowed to recover from customers the

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cost of purchased electricity. Therefore, should an approved supplier default and ComEd be required to purchase replacement electricity, ComEd would be entitled to recover these costs from customers.

Transmission congestion. ComEd and PECO have made, and expect to continue to make, significant capital expenditures to ensure the adequate capacity and reliability of their transmission systems. On an ongoing basis, PJM, in cooperation with ComEd and PECO, performs screening analyses based on forecasts of future transmission system conditions in order to determine system reinforcements needed to maintain the reliable operation of both systems.

Loss of electricity customers to other generation suppliers. When ComEd’s and PECO’s respective customers choose alternative electric generation suppliers, ComEd and PECO lose their associated revenues. In the case of PECO, operating results are not affected by customers choosing an alternative supplier since lost revenues are completely offset by decreased purchased power expense. In ComEd’s case, the loss of revenues is largely offset by related reduced purchased power expense resulting in operating results being impacted only by any lost margin.

With respect to planning for electricity supply, ComEd and PECO have no obligation to purchase power reserves to cover the load served by others. ComEd and PECO manage their POLR obligations through full-requirements contracts with Generation, under which Generation supplies the electricity requirements of ComEd and PECO. Also, ComEd has sought through the regulatory process, as permitted by law, to limit the POLR obligation for those customers that do have competitive supply options. In 2003, ComEd received ICC approval to phase out over several years its obligation to provide fixed-price electricity under bundled rates to approximately 370 of its largest electricity customers, which have demands of at least three MWs and represent an aggregate of approximately 2,500 MWs of load. To date, ComEd has not requested to phase out its obligation to provide fixed-price electricity under bundled rates for other customers but continues to evaluate its options.

Generation

Costs to meet contractual commitments. Generation’s resources include interests in 11 nuclear generation stations, consisting of 19 units in operation. Generation’s nuclear fleet plus its ownership interest in the Salem Generating Station, operated by PSEG Nuclear, generated 137,936 GWhs, or approximately 90% of Generation’s total output, for the year ended December 31, 2005. As the largest generator of nuclear power in the United States, Generation can negotiate favorable terms for the materials and services that its business requires. Generation’s nuclear plants have historically benefited from stable fuel costs, minimal environmental impact from operations and a safe operating history.

Refueling outages.Generation continues to maintain the decreased average length of refueling outages achieved in recent years at the nuclear stations it operates, resulting in a stable generation base for Power Team trading activities.

Operating services arrangement.In 2005, as a result of the OSC with PSEG Nuclear, Generation is providing services to oversee daily plant operations and guidance to implement the Exelon Nuclear Management Model at the Salem and Hope Creek nuclear generating stations. As a result, Generation has decreased certain exposures in 2005 and increased revenues from its share of the Salem Generating Station, which it co-owns with PSEG Nuclear.

Adequacy of funds to decommission nuclear power plants.In 2003, the 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. See the risk factor “Generation’s financial performance may be negatively affected by liabilities arising from its ownership and operation of

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nuclear facilities” for further detail. Generation has reviewed the GAO’s report and believes 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. Generation currently believes that the amounts in nuclear decommissioning trust funds and future collections from ComEd’s and PECO’s customers, together with earnings thereon, will provide adequate funding to decommission its nuclear facilities in accordance with regulatory requirements.

Credit risk.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 enabling agreements that allow for netting of payables and receivables with the majority of its large counterparties. The credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis. Due to the termination of its PPA with ComEd on December 31, 2006 and its obligation to auction off output from its nuclear plants mandated by the FERC order approving the Merger, Generation’s liquidity requirements and credit risk exposure could increase.

Extreme weather.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.

Wholesale energy market prices.The price of power purchased and sold in the open wholesale energy markets can vary significantly in response to market conditions. Generally, between 60% and 70% of Generation’s supply serves ComEd and PECO customers. Consequently, Generation has limited its earnings exposure from the volatility of the wholesale energy market to the energy generated in excess of the ComEd and PECO requirements, as well as any other contracted longer term obligations. Following the expiration of the PPA arrangement with ComEd at the end of 2006, Generation’s supply will be more exposed to energy market prices.

Commodity prices.Generation’s Power Team manages the output of Generation’s assets and energy sales to optimize value and reduce the volatility of Generation’s earnings and cash flows. Generation attempts to manage its exposure through enforcement of established risk limits and risk management procedures.

General Business

Security risk.The Registrants have initiated and work to maintain security measures. See “Security” in ITEM 1. Business for further detail. On a continuing basis, the Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans and assess 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.

Potential phase-out of tax credits.Tax credits generated by the production of synthetic fuel are subject to a phase-out provision that gradually reduces tax credits in the event crude oil prices for a year exceed certain thresholds. See the risk factor “Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact the Registrants’ results of operations” in ITEM 1A. Risk Factors for further detail. In 2005, Exelon and

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Generation entered into certain derivatives to economically hedge a portion of the oil price exposure related to the phase-out of tax credits. These derivatives could result in after-tax cash proceeds to Exelon of up to $42 million per year in 2006 and 2007 in the event the tax credits are completely phased out. See Note 12 of Exelon’s Notes to Consolidated Financial Statements and the Executive Overview in Management’s Discussion and Analysis of Financial Condition and Results of Operation for further detail.

Interest rates. Exelon uses a combination of fixed-rate and variable-rate debt to reduce interest-rate exposure. Exelon also uses interest-rate swaps when deemed appropriate to adjust exposure based upon market conditions. Additionally, Exelon uses forward-starting interest-rate swaps and treasury rate locks to lock in interest-rate levels in anticipation of future financings. See ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk for further information.

Executive Officers of the Registrants at December 31, 2005

Exelon

Name	Age	Position
Rowe, John W.	60	Chairman, Chief Executive Officer and President
Clark, Frank M.	60	Chairman and Chief Executive Officer, ComEd
McLean, Ian P.	56	Executive Vice President and President, Power Team
Mehrberg, Randall E.	50	Executive Vice President and General Counsel
Moler, Elizabeth A.	56	Executive Vice President, Governmental and Environmental Affairs and Public Policy
Skolds, John L.	55	Executive Vice President, President, Exelon Energy Delivery and President, Exelon Generation
Snodgrass, S. Gary	54	Executive Vice President and Chief Human Resources Officer
Young, John F.	49	Executive Vice President, Finance and Markets and Chief Financial Officer
Hilzinger, Matthew F.	42	Senior Vice President and Corporate Controller

ComEd

Name	Age	Position
Clark, Frank M.	60	Chairman and Chief Executive Officer
Mitchell, J. Barry	57	President
Costello, John T.	57	Executive Vice President and Chief Operating Officer
McDonald, Robert K.	50	Senior Vice President, Chief Financial Officer, Treasurer and Chief Risk Officer
Pramaggiore, Anne R.	47	Senior Vice President, Regulatory and External Affairs
Hooker, John T.	57	Senior Vice President, Legislative and Governmental Affairs
Hilzinger, Matthew F.	42	Senior Vice President and Corporate Controller, Exelon (Principal Accounting Officer)

PECO

Name	Age	Position
Rowe, John W.	60	Chairman, Chief Executive Officer and President, Exelon, and Director
Young, John F.	49	Executive Vice President, Finance and Markets and Chief Financial Officer, Exelon, and Chief Financial Officer
Skolds, John L.	55	President, Exelon Energy Delivery, and Director
O’Brien, Denis P.	45	President and Director
Hilzinger, Matthew F.	42	Senior Vice President and Corporate Controller, Exelon (Principal Accounting Officer)

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Generation

Name	Age	Position
Rowe, John W.	60	Chairman, Chief Executive Officer and President, Exelon
Young, John F.	49	Executive Vice President, Finance and Markets and Chief Financial Officer, Exelon, and Chief Financial Officer
Skolds, John L.	55	Executive Vice President, Exelon, and President
McLean, Ian P.	56	Executive Vice President, Exelon, and President, Power Team
Crane, Christopher M.	47	Senior Vice President, Exelon, and President and Chief Nuclear Officer, Exelon Nuclear
Schiavoni, Mark A.	50	Senior Vice President and President, Exelon Power
Veurink, Jon D.	41	Vice President and Controller

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 positions, Mr. Rowe was President and Co-Chief Executive of Exelon, Co-Chief Executive Officer of ComEd and President, Co-Chief Executive Officer of PECO; and Chairman, President and Chief Executive Officer of ComEd and Unicom. Mr. Rowe was elected as an officer of Exelon effective October 20, 2000.

Prior to his election to his listed position, Mr. Clark was Vice President and Chief of Staff of Exelon and President of ComEd; 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. Mr. Clark was elected Chairman of ComEd effective November 28, 2005.

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. Mr. McLean was elected as an officer of Exelon effective October 20, 2000.

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. Mr. Mehrberg was elected as an officer of Exelon effective December 3, 2001.

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. Ms. Moler was elected as an officer of Exelon effective October 20, 2000.

Prior to his election to his listed positions, Mr. Skolds was Senior Vice President, Exelon, and President and Chief Nuclear Officer, Exelon Nuclear; and President and Chief Operating Officer of South Carolina Electric and Gas. Mr. Skolds was elected as an officer of Exelon effective October 20, 2000.

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. Mr. Snodgrass was elected as an officer of Exelon effective October 20, 2000.

Prior to his election to his listed positions, Mr. Young was President of Exelon Generation; President of Exelon Power; Senior Vice President of Sierra Pacific Resources Corporation; President of Avalon Consulting; and Executive Vice President of Southern Generation. Mr. Young was elected as an officer effective March 3, 2003.

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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; and Assistant Treasurer of Kmart Corporation. Mr. Hilzinger was elected as an officer of Exelon effective April 15, 2002.

Prior to his election to his listed position, Mr. Mitchell was Senior Vice President, Chief Financial Officer and Treasurer of Exelon, ComEd, PECO and Generation; Vice President and Treasurer of Exelon; and Vice President, Treasury and Evaluation, and Treasurer of PECO. Mr. Mitchell was elected as President of ComEd effective November 28, 2005.

Prior to his election to his listed position, Mr. Costello served as Senior Vice President of Exelon Energy Delivery Technical Services. Mr. Costello has also served as Senior Vice President of Exelon Energy Delivery Customer and Marketing Services; and Vice President, Customer Operations. Mr. Costello was elected to his listed position with ComEd effective November 28, 2005.

Prior to his election to his listed position, Mr. McDonald served as Senior Vice President of Planning and Chief Risk Officer of Exelon. Mr. McDonald has also served as Chief Risk Officer of Exelon, Vice President of Planning of Exelon and Vice President of Risk Management of Exelon. He was elected to his listed position with ComEd effective November 28, 2005.

Prior to her election to her listed position, Ms. Pramaggiore served as Vice President, Regulatory and Strategic Services of ComEd. She has also served as Lead Counsel of ComEd. Ms. Pramaggiore was elected to her listed position with ComEd effective November 28, 2005.

Prior to his election to his listed position, Mr. Hooker served as Senior Vice President, ComEd, Legislative and External Affairs and Exelon Energy Delivery Real Estate and Property Management. Mr. Hooker has also served as Vice President Exelon Energy Delivery Property Management and ComEd Legislative and External Affairs; Vice President Distribution Services and Public Affairs; and Vice President of Governmental Affairs.

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. Mr. O’Brien was elected as an officer of PECO effective January 1, 2001.

Prior to his election to his listed position, Mr. Crane was Vice President for Exelon Nuclear; and Vice President for BWR Operations of ComEd. Mr. Crane was elected as an officer of Generation effective December 27, 2000.

Prior to his election to his listed position, Mr. Schiavoni was Vice President of Operations; and Vice President of Northeast Operations of Exelon Power. Mr. Schiavoni was elected as an officer of Generation effective September 8, 2003.

Prior to his election to his listed position, Mr. Veurink was a partner at Deloitte & Touche LLP. Mr. Veurink was elected as an officer of Generation effective January 5, 2004.

ITEM 1A. RISK FACTORS

Exelon, ComEd, PECO and Generation operate in a market environment that involves significant risks, many of which are beyond their control. The following risk factors, as well as the risks discussed in ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation—Exelon—Liquidity and Capital Resources, may adversely impact the Registrants’ results of operations,

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cash flows and market price of their publicly traded securities. While each of the Registrants believes it has identified and discussed below the key risk factors affecting its business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant that may adversely affect its performance or financial condition.

ComEd and PECO

Regulatory Risks

The process for establishing ComEd’s and PECO’s rates after the rate freeze and rate caps expire is contentious, in view of requested rate increase requests, and involves uncertainty as to their form and adequacy.

ComEd and PECO cannot currently predict the ultimate outcomes of the actions by the Illinois and Pennsylvania state regulators for establishing rates after the rate freeze and caps expire. Nevertheless, the expectation is that ComEd and PECO will continue to be obligated to deliver electricity to customers in their respective service territories and will also retain significant POLR obligations, whereby each utility is required to provide electricity service to customers in its service area who choose to obtain their electricity from the utility. ComEd has filed two proceedings seeking regulatory approval of the process by which it proposes to procure electricity and the rates it proposes to charge to deliver electricity to customers. Various governmental parties and consumer groups have contested the proposed electricity procurement process as well as the requests made in the proceedings. The ultimate outcome of these matters, and in particular the ComEd Procurement case in Illinois and regulatory proceedings related to the end of PECO’s transition period, will have a significant effect on the ability of ComEd and PECO, as applicable, to recover their costs and could have a material adverse effect on ComEd’s and PECO’s results of operations and cash flows.

ComEd may be required to sell electricity at capped rates while buying electricity at market rates, which are more volatile and potentially higher.

Although the ICC has issued an order authorizing the reverse-auction competitive bidding process for procurement of power after 2006, that decision remains subject to petitions for rehearing and is likely to be challenged in court. ComEd cannot predict the results of those challenges or whether the Illinois General Assembly might take action that could have a material impact on the procurement process. If the price at which ComEd is allowed to sell electricity beginning in 2007 is below ComEd’s cost to procure and deliver electricity, there may be material adverse consequences to ComEd and, possibly, Exelon. Exelon and ComEd believe that these potential material adverse consequences could include, but may not be limited to, loss of ComEd’s investment grade credit rating and a possible reduction in the other Registrants’ credit ratings, limited or lost access for ComEd to credit markets to finance operations and capital investment, and loss of ComEd’s capacity to enter into bilateral long-term electricity procurement contracts, which would likely force ComEd to procure electricity at more volatile and potentially higher prices in the spot market. Moreover, to the extent ComEd is not permitted to recover its costs, ComEd’s ability to maintain and improve service may be diminished and its ability to maintain reliability may be impaired. In the nearer term, these prospects could have adverse effects on ComEd’s liquidity if vendors reduce credit or shorten payment terms or if ComEd’s financing alternatives become more limited and significantly less flexible. In addition, ComEd has indicated it is willing to develop a “cap and deferral” arrangement to keep residential rates at or below 1996 levels through 2009. A “cap and deferral” arrangement would limit the procurement costs that ComEd could pass through to its customers for a period of time and allow ComEd to collect those unrecovered costs in future years.

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Changes in ComEd’s and PECO’s terms and conditions of service, including their respective rates, are subject to regulatory approval proceedings that are contentious, lengthy and subject to appeal, which introduce time delays in effecting rate changes as well as uncertainty as to the ultimate result.

ComEd and PECO are involved in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services. These proceedings typically involve multiple parties, including governmental bodies and officials, 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 generally have long time lines, which may not be limited by statute. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings.

ComEd’s and PECO’s ability to cover their respective operating and capital costs may be limited by rate caps currently in effect, which will affect their respective results of operations during the rate cap period.

The rate freezes or caps in effect at ComEd and PECO currently limit their ability to recover increased operating expenses and to recover the costs of investments in new transmission and distribution facilities. ComEd is subject to a rate freeze on bundled retail rates that will remain in effect through January 1, 2007. PECO is subject to rate caps on its transmission and distribution rates through December 31, 2006 and on its generation rates through December 31, 2010. The transmission and distribution rate caps at PECO may be extended to December 31, 2010 as a result of a settlement in the Merger approval process in Pennsylvania. See Note 4 of Exelon’s Notes to Consolidated Financial Statements for further information.

ComEd and PECO expect to continue to make significant capital expenditures to maintain and improve the reliability of their transmission and distribution systems and for capital additions to support new business and customer growth. As a result, ComEd’s and PECO’s future results of operations, during the periods indicated above, may be adversely affected if ComEd and PECO are not able to deliver electricity in a cost-efficient manner and are unable to offset inflation and the cost of infrastructure investments with cost savings. Their ability to identify and implement cost savings is more challenging in the later years of the freeze and caps. Further, the rate freeze and caps will generally preclude rate recovery on any of its incremental capital investments through January 2, 2007.

A mandatory RPS could negatively affect the cost of electricity purchased and sold by ComEd and PECO.

Federal or state legislation mandating the use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal, could result in significant changes in ComEd’s and PECO’s businesses, including fuel cost and capital expenditures. ComEd and PECO continue to monitor discussions related to RPSs at the Federal and state levels.

For additional information, see “Environmental Regulation—Renewable and Alternative Energy Portfolio Standards” in ITEM 1 of this Form 10-K.

Operating Risk

ComEd and PECO may be subject to the risk of power supplier defaults and the unplanned costs associated with those defaults.

Neither ComEd nor PECO own generation facilities. Both currently purchase their electricity from Generation pursuant to PPAs that expire at the end of 2006, in the case of ComEd, and the end of 2010, in the case of PECO. Assuming a competitive procurement process thereafter, both companies

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may be subject to supplier defaults and supply risk. If a supplier defaults, ComEd or PECO, as the case may be, would be required to purchase replacement electricity in the spot market to meet the needs of its customers, which may increase electricity purchase and transmission costs and negatively affect results of operations.

ComEd’s and PECO’s respective ability to deliver electricity, their operating costs and their capital expenditures may be negatively affected by transmission congestion.

Demand for electricity within ComEd’s and PECO’s service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage with consequent effects on operating costs, revenues and results of operations. In addition, as with all utilities, potential concerns over transmission capacity could result in PJM or the FERC requiring ComEd and PECO to upgrade or expand their respective transmission system through additional capital expenditures.

ComEd’s and PECO’s operating costs and their respective perception by customers and regulators are affected by their ability to maintain the availability and reliability of their delivery systems.

Failures of the equipment or facilities used in ComEd’s and PECO’s delivery systems can interrupt the delivery of electricity and related revenues and increase repair expenses and capital expenditures. Those failures or those of other utilities, including prolonged or repeated failures, can affect customer satisfaction, the level of regulatory oversight and ComEd’s and PECO’s maintenance and capital expenditures. Regulated utilities, which 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. Under Illinois law, however, ComEd can be required to pay damages to its customers in the event of extended outages affecting large numbers of its customers.

ComEd and PECO face the continued loss of electricity customers and associated revenues to other generation suppliers since those customers have the right to select their own generation supplier.

ComEd’s and PECO’s retail electric customers may purchase their electricity from alternative electric suppliers, although ComEd and PECO remain obligated to provide transmission and distribution service to customers in their service territories regardless of their generation supplier. ComEd and PECO are each 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 supplier may later return to ComEd or PECO. The number of customers taking service from alternative electric suppliers depends in part on the prices being offered by those suppliers relative to the fixed prices that ComEd and PECO are authorized to charge by their state regulatory commissions. To the extent that customers leave traditional bundled tariffs and select a different electric supplier, ComEd’s and PECO’s revenues are likely to decline, and revenues and gross margins could vary from period to period.

The effect of higher purchased gas cost charges to customers may decrease PECO’s results of operations and cash flows.

Gas rates charged to customers are comprised primarily of purchased gas cost charges, which provide no return or profit to PECO, and distribution charges, which provide a return or profit to PECO. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted quarterly, represent gas commodity costs that PECO recovers from customers. PECO’s cash flows can be impacted by differences between the time period when gas is purchased and the ultimate recovery from customers. When purchased gas cost charges increase substantially, as they have throughout

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2005 in response to higher gas procurement costs incurred by PECO, customer usage may decrease, resulting in lower distribution charges and lower profit margins for PECO. In addition, increased purchased gas cost charges to customers also may result in increased bad debt expense from an increase in the number of uncollectible accounts receivable.

The effects of weather and the related impact on electricity and gas usage may decrease ComEd’s and PECO’s results of operations.

Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below moderate levels in the winter tend to increase winter heating electricity and gas demand and revenues. As a corollary, moderate temperatures adversely affect the usage of energy and resulting revenues. Because of seasonal pricing differentials, coupled with higher consumption levels, ComEd and PECO typically report higher revenues in the third quarter of the fiscal year. However, extreme weather conditions or storms may stress ComEd’s and PECO’s transmission and distribution systems, resulting in increased maintenance and capital costs and limiting its ability to meet peak customer demand. These extreme conditions may have detrimental effects on ComEd’s and PECO’s operations.

ComEd’s and PECO’s businesses are capital intensive and the costs of capital projects may be significant.

ComEd’s and PECO’s businesses are capital intensive and require significant investments in internal infrastructure projects. ComEd’s and PECO’s results of operations and financial condition could be adversely affected if either is unable to effectively manage their respective capital projects.

Other

Exelon’s and ComEd’s goodwill may become further impaired, which would result in write-offs of the impaired amounts.

Exelon and ComEd had approximately $3.5 billion of goodwill recorded at December 31, 2005. This goodwill was recognized and recorded in connection with the PECO / Unicom merger. With the proposed Merger with PSEG, it is anticipated that approximately $6 billion to $7 billion of additional goodwill will be recorded at Exelon across various business units. See the Merger section below for further discussion. Under GAAP, the goodwill will remain at its recorded amount unless it is determined to be impaired, which is based upon an annual analysis prescribed by SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142) that compares the implied fair value of the goodwill to its carrying value. If an impairment occurs, such as the one recorded during 2005, the amount of the impaired goodwill will be written off and expensed, reducing equity. Under Illinois law, any impairment of goodwill has no impact on the determination of ComEd’s rate cap through the transition period.

There is a possibility that additional goodwill may be impaired at ComEd, and at Exelon, in 2006 or later periods. The actual timing and amounts of any goodwill impairments in future years will depend on many sensitive, interrelated and uncertain variables, including changing interest rates, utility sector market performance, ComEd’s capital structure, market prices for power, results of ComEd’s post 2006 rate proceedings, operating and capital expenditure requirements and other factors, some not yet known.

See Critical Accounting Policies and Estimates for further discussion on goodwill impairments.

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Generation

Market Transition Risks

Generation will be exposed to increased market risk and price volatility after the expiration of significant purchase power arrangements after 2006.

Generation sells a majority of its output to ComEd and PECO under long-term PPAs. As a result of the pending expiration of the PPA between Generation and ComEd at the end of 2006, Generation will be exposed to increased commodity price risk associated with the electricity historically sold to serve ComEd’s load obligations. Generation will continue to be exposed to fluctuations in commodity prices for electricity after 2006 for the unhedged portion of its electricity trading portfolio. Generation has been and will continue to be proactive in looking for hedging strategies to mitigate this risk. Accordingly, Generation may need to sell more electricity at market-based prices than it currently does. Increased market sales and new contractual arrangements under a competitive model may adversely affect Generation’s credit risk due to an increase in the number of customers and the loss of a highly predictable revenue source.

Although the order issued by the ICC authorizes the reverse-auction competitive bidding process for procurement of power after 2006 for ComEd, that decision remains subject to petitions for rehearing and is likely to be challenged in court. In addition, the Illinois General Assembly has held hearings concerning generation procurement post 2006 and it may choose to take further action on this issue. In April 2005, a proposed amendment to the Illinois Public Utilities Act was introduced in Committee hearings in the Illinois legislature, which, if enacted into law, would have extended the current “rate freeze” and transition period for an additional two years. However, the proposed amendment was defeated in Committee.Generation cannot predict the results of those challenges or whether the Illinois General Assembly might take further action that could have a material impact on Generation, including actions that would attempt to require Generation to enter into a full requirements PPA with ComEd to sell power at below market prices beginning in 2007.

Generation’s business may be negatively affected by the restructuring of the energy industry.

Regional Transmission Organizations.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.

Wholesale markets have only been implemented in certain areas of the country and each market has unique features which may create trading barriers among the markets. The FERC has proposed initiatives, including RTOs, to encourage the development of large regional, uniform markets and to eliminate trade barriers. The FERC’s effort to promote RTOs throughout the states has generated substantial opposition by some state regulators and other governmental bodies. In addition, efforts to develop a RTO have been abandoned in certain regions. Generation supports the development of RTOs and implementation of standard market protocols for these regions, and others, but cannot predict their success or whether they will lead to the development of the large, successful wholesale markets.

Approximately 79% of Generation’s generating resources, which include directly owned assets and capacity obtained through long-term contracts, are located in the region encompassed by PJM, following PJM’s expansion to the Midwest markets in 2004. The PJM market has been the most successful and liquid regional market. Generation’s future results of operations may be negatively affected by the continued expansion of that market or the implementation of any market changes mandated by the FERC.

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Provider of Last Resort.As discussed above, ComEd and PECO have POLR obligations that they have effectively transferred to Generation through full-requirements contracts. Because the choice of an 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 electricity demand of ComEd and PECO customers. The uncertainty regarding the amount of ComEd and PECO load for which Generation must provide increases Generation’s costs and may limit its sales opportunities. A significant under-estimation of the electric-load requirements of ComEd and PECO 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 Generation’s total costs.

Generation may not be able to effectively 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. These new generating facilities may be more efficient than Generation’s 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.

Generation may not be able to effectively respond to increased demand for energy.

As the demand for electricity rises in the future, it may be necessary to increase capacity through the construction of new generating facilities. Both Illinois and Pennsylvania statutes contemplate that future generation will be built at the risk of market participants. Any construction of new generating facilities by Generation would be subject to market concentration tests administered by the FERC. If Generation cannot pass these tests administered by the FERC, it could be limited in how it responds to increased demand for energy. Generation’s financial growth depends on its ability to respond to increased demand for energy.

Nuclear Operations Risks

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

Nuclear capacity factors. Capacity factors, particularly nuclear capacity factors, significantly affect Generation’s results of operations. Nuclear plant operations involve substantial fixed operating costs but produce electricity at low variable costs due to nuclear fuel costs typically being lower than fossil fuel costs. Consequently, to be successful, Generation must consistently operate its nuclear facilities at high capacity factors. Lower capacity factors increase Generation’s operating costs by requiring 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 have a higher operating cost than Generation incurs to generate energy from its 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 24 days in duration. When refueling outages at wholly and co-owned plants last longer than anticipated or Generation experiences unplanned outages, capacity factors decrease and Generation faces lower margins due to higher energy replacement costs and/or lower energy sales. Each 24-day outage, depending on the capacity of the station, will decrease the total nuclear annual

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capacity factor between 0.3% and 0.5%. The number of refueling outages, including the AmerGen plants and the co-owned plants, was eleven in 2005 with eleven planned for 2006. The projected total non-fuel capital expenditures for the nuclear plants operated by Generation will increase in 2006 compared to 2005 by approximately $39 million as Generation continues to invest in equipment upgrades to ensure safe reliable operations. Maintenance expenditures are expected to increase by approximately $67 million in 2006 compared to 2005 as a result of inflationary cost increases and one additional planned nuclear outage at the nuclear stations operated and wholly owned by Generation.

Nuclear fuel quality. The quality of nuclear fuel utilized by Generation can affect the efficiency and costs of Generation’s 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, could result in increased costs due to accelerated fuel amortization and/or increased outage costs. It is difficult to predict the total cost of these remediation procedures.

Spent nuclear fuel storage.Generation incurs costs on an annual basis for the storage of spent nuclear fuel. Under the terms of the settlement reached with the DOE in 2004, Generation is being reimbursed for costs of spent fuel storage only after costs are incurred and only for costs resulting from DOE delays in accepting the fuel. The approval of a national repository for the storage of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, and the timing of such facility opening, will significantly affect the costs associated with storage of spent nuclear fuel, and the ultimate amounts received from the DOE under the settlement. Also, the availability of a repository for spent nuclear fuel may affect the ability to fully decommission the nuclear units. In addition, the State of Nevada recently challenged the NRC’s “waste confidence” rule, 10 CFR 51.23, pursuant to which, the NRC has determined that, if necessary, spent fuel generated in any reactor can be stored safely and without significant environmental impacts for at least 30 years beyond the licensed life for operation, which may include the term of a revised or renewed license of that reactor, at its spent fuel storage basis or at either onsite or offsite independent spent fuel storage installations. The rule remains in place at this time, and is unlikely to be revised in the near future unless the D.C. Circuit overturns the NRC’s denial of Nevada’s petition. Under the waste confidence rule, the NRC has made a determination that, if necessary, spent fuel generated in any reactor can be stored safely and without significant environmental impacts for at least 30 years beyond the licensed life for operation, which may include the term of a revised or renewed license, of that reactor at its spent fuel storage basis or at either onsite or offsite independent spent fuel storage installations. If the NRC changes or is forced to change its determination it could affect the nuclear generating stations ability to store additional waste.

License Renewals. Generation’s nuclear facilities are currently operating under 40-year NRC licenses. Generation has applied for and received 20-year renewals for the licenses that will be expiring in the next ten years or, in the case of Oyster Creek, an order that will permit Oyster Creek to operate beyond its license expiration in April 2009 if the NRC has not completed reviewing the application for renewal. Generation intends to evaluate opportunities, as permitted by the NRC, to apply for license renewals for some or all of the remaining licenses. If the renewals are granted, Generation cannot assure that economics will support the continued operation of the facilities for all or any portion of the renewed license. If the NRC does not renew the operating licenses for Generation’s nuclear stations or a station cannot be operated until the end of its operating license, Generation’s results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning payments.

Should a national policy for the disposal of spent nuclear fuel not be developed, the unavailability of a repository for spent nuclear fuel could become a consideration by the NRC during future nuclear license renewal proceedings, including applications for new licenses, and may affect Generation’s ability to fully decommission its nuclear units.

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Environmental risk.In July 2004, the EPA issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. This rule establishes national requirements for reducing the adverse environmental impacts from the entrainment and impingement of aquatic organisms at existing power plants. The rule identifies particular standards of performance with respect to entrainment and impingement and requires each facility to monitor and validate this performance in future years. The requirements will be implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g. cooling towers) are potentially most affected. Those facilities are Clinton, Cromby Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, New Boston, Oyster Creek, Peach Bottom, Quad Cities and Salem. During the NJDEP system permit renewal process for both Salem and Oyster Creek, the NJDEP primarily concluded that closed-cycle cooling for Salem and Oyster Creek and environmental restoration for Oyster Creek are the only viable compliance options for Section 316(b). See ITEM 1. Business section for further details on Environmental Water Regulations. AmerGen and PSEG have not made a determination regarding how compliance of Section 316(b) will be met for Oyster Creek and Salem. If application of the Section 316(b) regulations requires the retrofitting of Oyster Creek and Salem’s cooling water intake structure, or extensive wetlands restoration, this could result in material costs of compliance. In addition, the amount of the costs required to retrofit Oyster Creek may negatively impact Generation’s decision to renew the operating license.

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 operations 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.

In January 2004, the NRC issued a letter to PSEG to conduct a review of its Salem facility, of which Generation owns 42.59%, to assess the workplace environment for raising and addressing safety issues. Since that time, PSEG has worked with the NRC under its oversight program to address the matters, which focus on a safety conscious work environment, raised by the NRC’s letter. Throughout 2005, PSEG has and will continue to provide updated information to the NRC as required under their workplan.

The spent fuel pool at each Salem Unit has an installed leakage collection system. This normal leakage path was found to be obstructed, causing concern about the extent of leakage contact with the fuel handling building’s concrete structure. PSEG is developing a solution to maintain the design function of the leakage collection system and is investigating the extent of any structural degradation caused by the leakage. The investigation should take approximately one year. If any significant degradation is identified, the repair costs to the owners of the facility could be material. The NRC issued Information Notice 2004-05 in March 2004 concerning this emerging industry issue and Generation cannot predict what further actions the NRC may take on this matter.

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Nuclear accident risk. Although the safety record of nuclear reactors, including Generation’s, generally 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 liability from a nuclear accident may exceed Generation’s resources, including insurance coverages, and significantly affect Generation’s results of operations or financial position.

Nuclear 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 December 31, 2005 is $10.76 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. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $10.76 billion limit.

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 2005 was $40 million, which was recorded as a reduction to operating and maintenance expenses in its Consolidated Statement of Income. Generation cannot predict the level of future distributions or if they will continue at all.

Decommissioning. Generation has an obligation to decommission its nuclear power plants. The ICC permits ComEd, and the PAPUC permits PECO, to collect funds from their customers, which are deposited in nuclear decommissioning trust funds maintained by Generation. Collections by ComEd are limited and permitted only through 2006. The collections by ComEd and PECO are based on estimates of decommissioning costs for each of the nuclear facilities in which Generation has an ownership interest, other than AmerGen 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 in 2005 and 2006. Because ComEd did not take all of the output of these stations, actual collections were $68 million in 2005 and are expected to be approximately the same in 2006. Subsequent to 2006, there will be no further recoveries of decommissioning costs from ComEd’s customers. PECO is currently recovering $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. These trust funds, together with earnings thereon, will be used to decommission such nuclear facilities. Decommissioning expenditures are expected to occur primarily after the plants are retired. Based on current licenses and anticipated renewals, decommissioning expenditures for plants in operation are currently estimated to begin in 2029. To fund future decommissioning costs, Generation held $5.6 billion of investments in trust funds at December 31, 2005.

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) including scheduled contributions to and earnings on the decommissioning trust funds. As of December 31, 2005, one of Generation’s 23 units is currently underfunded by less than three percent with respect to NRC Funding Levels. Generation will submit its next biennial report to the NRC in March 2006.

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In 2003, 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. Forecasting investment earnings and costs to decommission nuclear generating stations requires significant 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 provide other means of funding its decommissioning obligations.

Other Operating Risks

Financial performance and load requirements may be adversely affected if Generation is unable to effectively manage its power portfolio.

The majority of Generation’s portfolio is used to provide power under long-term PPAs with ComEd and PECO. To the extent portions of the portfolio are not needed for that purpose, Generation’s output is sold on the wholesale market. To the extent its portfolio is not sufficient to meet the requirements of ComEd and PECO, Generation must purchase power in the wholesale power markets. Generation’s financial results may be negatively affected if it is unable to cost-effectively meet the load requirements of ComEd and PECO, manage its power portfolio and effectively handle the changes in the wholesale power markets.

Generation relies on the availability of electric transmission facilities that it does not own or control to deliver its wholesale electric power to the purchasers of the power, which may adversely affect its ability to deliver power to its customers.

Generation depends on transmission facilities owned and operated by other companies, including ComEd and PECO, 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. 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 commenced 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 exposed to price fluctuations and other risks of the wholesale power market that are beyond its control, which may negatively impact its results of operations.

Generation fulfills its energy commitments from the output of the generating facilities that it owns as well as through buying electricity under long- and short-term contracts 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. Generation’s cash flows from generation

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that is not used to meet its commitments to ComEd and PECO are largely dependent on wholesale prices of electricity and Generation’s 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 and Generation would be required to incur an impairment loss.

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 will not perform their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, Generation might be forced to purchase or sell power in the wholesale markets at less favorable 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 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. Due to the termination of its PPA with ComEd on December 31, 2006 and its obligation to auction off output from its nuclear plants mandated by the FERC order approving the Merger, Generation’s liquidity requirements and credit risk exposure could increase.

In addition, the retail businesses of Exelon Energy subject Generation to credit risk resulting from a different customer base.

Risk of Credit Downgrades. Generation’s trading business is required to meet credit quality standards. If it were to lose its investment grade credit rating or otherwise fail to satisfy the credit standards of trading counterparties, Generation would be required under trading agreements to provide collateral in the form of letters of credit or cash, which may materially adversely affect its liquidity. If Generation had lost its investment grade credit as of December 31, 2005, it would have been required to provide approximately $1,388 million in collateral.

Immature Markets.Certain 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 portfolio. 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

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weather 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 effect 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.

Power Team’s risk management policies cannot fully eliminate the risk associated with its energy 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 work as planned and cannot eliminate all risks associated with these activities. Even when its 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 incorrect. 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.

Generation’s business is capital intensive and the costs of capital projects may be significant.

Generation’s business is capital intensive and requires significant investments in energy generation and in other internal infrastructure projects. Generation’s results of operations could be adversely affected if Generation were unable to effectively manage its capital projects.

General Business

The following risk factors may adversely impact all of the Registrants’ results of operations and cash flows.

Results of operations may be negatively affected by increasing costs.

Inflation affects the Registrants through increased operating costs and increased capital costs for plant and equipment. As a result of the rate freezes for ComEd and caps for PECO under which the businesses operate and price pressures due to competition, ComEd and PECO may not be able to pass the costs of inflation through to their customers. In addition, the Registrants face rising medical benefit costs, which are increasing at a rate that greatly exceeds the rate of general inflation. If the Registrants are unable to successfully manage their medical benefit costs or other increasing costs, their results of operations could be negatively affected.

Market performance may decrease the value of decommissioning trust funds and benefit plan assets, which then could require significant additional funding.

The performance of the capital markets affects the values of the assets that are held in trust to satisfy future obligations to decommission Generation’s nuclear plants and under Exelon’s pension and postretirement benefit plans. The Registrants have 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 the funding requirements of these obligations.

Exelon’s holding company structure could limit its ability to pay dividends.

Exelon is a holding company with no material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Exelon’s ability to pay dividends on

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its common stock depends on the payment to it of dividends by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. Under applicable Federal law, ComEd, PECO and Generation can pay dividends only from the amount of retained, undistributed or current earnings. Under Illinois law, ComEd may not pay any dividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless ComEd has specific authorization from the ICC. During 2005, a new board of directors with responsibilities solely for ComEd was selected. The ComEd board of directors may elect to adopt a different dividend policy.

The Registrants may incur substantial costs to fulfill their obligations related to environmental and other matters.

The businesses in which the Registrants operate are subject to extensive environmental regulation by local, state and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures. These regulations affect how the Registrants handle air and water emissions and solid waste disposal and are an important aspect of their operations. In addition, the Registrants are subject to liability under these laws for the costs of remediating environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generate. The Registrants have incurred and expect to incur significant costs related to environmental compliance, site remediation and clean-up. Remediation activities associated with MGP operations conducted by predecessor companies will be one component of such costs. Also, the Registrants are 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.

In addition, Generation is subject to exposure for asbestos-related personal injury liability alleged at certain current and formerly owned generation facilities. Future legislative action, such as that proposed in The Fairness in Asbestos Injury Resolution Act of 2005, could require Generation to contribute to a fund with a material contribution to settle lawsuits for alleged asbestos-related disease and exposure.

For additional information regarding environmental matters, see “Environmental Regulation” in ITEM 1 of this Form 10-K.

War, acts and threats of terrorism and natural disaster may adversely affect Exelon’s results of operations, its ability to raise capital and its future growth.

Exelon does not know the impact that any future terrorist attacks may have on the industry in general and on Exelon in particular. In addition, any retaliatory military strikes or sustained military campaign may affect its operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. The possibility alone that infrastructure facilities, such as electric generation, electric and gas transmission and distribution facilities, would be direct targets of, or indirect casualties of, an act of terror may affect Exelon’s operations. Additionally, the continuing military activity in Iraq and other wars may have an adverse effect on the economy in general. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect Exelon’s revenues or restrict its future growth. Instability in the financial markets as a result of terrorism or war may affect Exelon’s results of operations and its ability to raise capital. In addition, the implementation of security guidelines and measures have resulted in and are expected to continue to result in increased costs.

Additionally, Exelon is affected by changes in weather and the occurrence of hurricanes, storms and other natural disaster in its service territory and throughout the U.S. Severe weather or other

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natural disasters could be destructive which could result in increased costs, including supply chain costs. See Management’s Discussion and Analysis of Financial Conditions and Results of Operation—Executive Overview in ITEM 7 for additional information on the expected impact due to Hurricanes Katrina and Rita.

Changes in the availability and cost of insurance mean that the Registrants have greater exposure to economic loss due to property damage and liability.

The Registrants carry property damage and liability insurance for their properties and operations. As a result of significant changes in the insurance marketplace, the available coverage and limits may be less than the amount of insurance obtained in the past, the costs of obtaining such insurance may be higher and the recovery for losses due to terrorist acts may be limited. The Registrants are 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 their property damage and liability insurance, together with the deductible, could negatively affect their results of operations.

Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact the Registrants’ results of operations.

Tax reserves and the recoverability of deferred tax assets.The Registrants are required to make judgments regarding the potential tax effects of various financial transactions and results of operations in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate, sales and use and employment-related taxes and ongoing appeals issues related to these tax matters. These judgments include reserves for potential adverse outcomes regarding tax positions that have been taken. The Registrants also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Other than as noted below, the Registrants do not record valuation allowances for deferred tax assets related to capital losses that the Registrants believe will be realized in future periods. See Note 12 of Exelon’s Notes to Consolidated Financial Statements for further detail.

Increases in state income taxes.Due to the revenue needs of the states in which the Registrants operate, various state income tax and fee increases have been proposed or are being considered. The Registrants 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, or, 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 the Registrants’ results of operations and cash flows.

1999 Sale of the Fossil Generating Assets.Exelon, through its ComEd subsidiary, has taken certain tax positions, which have been disclosed to the Internal Revenue Service (IRS), to defer the taxation of the gain realized on the 1999 sale of its fossil generation assets. Exelon’s ability to continue to defer all or a portion of this liability depends on whether its treatment of a portion of the sale proceeds, as having been received in connection with an involuntary conversion, is proper pursuant to applicable law. Exelon’s ability to continue to defer the remainder of this liability may depend in part on whether its tax characterization of a lease transaction it entered into in connection with the sale is proper pursuant to applicable law. A successful IRS challenge to ComEd’s positions would have the impact of accelerating future income tax payments and increasing interest expense related to the deferred tax liability that becomes current. Federal tax returns covering the period of the 1999 sale are currently under IRS audit. Final resolution of this matter is not anticipated for several years. Exelon’s potential cash outflow, including tax and interest (after tax), could be as much as $951 million. It is presently unclear the extent to which the IRS will seek to disallow the deferral of tax liability resulting from the 1999 sale of fossil generating assets, if at all, and if it were to do so, the extent to which any

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such challenge would be successful. If the deferral were successfully challenged by the IRS, it could negatively impact Exelon’s results of operations by as much as $135 million (after tax). See Note 12 of Exelon’s Notes to Consolidated Financial Statements for further detail.

Investments in synthetic fuel-producing facilities. Exelon, through three wholly owned subsidiaries has investments in synthetic fuel-producing facilities. Section 45k of the Internal Revenue Code provides tax credits for the sale of synthetic fuel produced from coal. Exelon’s right to tax credits generated by the facilities was recorded as intangible assets which are amortized as the tax credits are earned. Section 45k contains a provision under which tax credits are phased out (i.e., eliminated) in the event crude oil prices for a year exceed certain thresholds. Recent events, such as terrorism, natural disasters and strong worldwide demand, have significantly increased the price of domestic crude oil and, therefore, have created uncertainty as to the value of future synthetic fuel tax credits and the net carrying value of the intangible assets. Exelon estimates that there could be a significant phase-out of tax credits in 2006 and 2007 based on the expected futures prices. Absent any efforts to mitigate price exposure, a phase-out could result in the reduction of non-operating net income generated by the investments and could result in substantial non-operating losses in 2006 and 2007 in the event all tax credits are completely eliminated. See Note 12 of Exelon’s Notes to Consolidated Financial Statements, the Executive Overview and Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operation for further detail.

Exelon and its subsidiaries have guaranteed the performance of third parties, which may result in substantial costs in the event of non-performance.

Exelon and certain of its subsidiaries have issued certain guarantees of the performance of others, which obligate Exelon to perform in the event that the third parties do not perform. In the event of non-performance of these guaranteed obligations by the third parties, Exelon and its subsidiaries could incur substantial cost to fulfill their obligations under these guarantees. Such performance could have a material impact on the financial statements of Exelon and its subsidiaries. See Note 20 of Exelon’s Notes to Consolidated Financial Statements for additional information regarding guarantees.

The Registrants may make acquisitions that do not achieve the intended financial results.

The Registrants may continue to pursue investments that fit their strategic objectives and improve their financial performance. With the repeal of PUHCA, the Registrants are free to make investments and pursue mergers and acquisitions that were formerly not permitted under PUHCA and that might present more risk than the types of investments and mergers and acquisitions that were permitted under PUHCA. However, with the repeal of PUHCA, it is possible that the public utility commissions of each state may impose certain other restrictions on the investments that the Registrants may make.

On December 20, 2004, Exelon announced the execution of the Merger Agreement with PSEG. Achieving the anticipated benefits of the Merger is subject to a number of uncertainties, including whether the businesses of Exelon and PSEG are integrated in an efficient and effective manner, as well as general competitive factors in the market place. Failure to achieve these anticipated benefits from the Merger or other strategic investments could result in increased costs, decreases in the amount of expected revenues generated by the combined company and diversion of management’s time and energy and could have an adverse effect on the combined company’s business, financial condition, operating results and prospects. See the Proposed Merger with PSEG section below for further risk information.

Proposed Merger with PSEG

The business of PSEG and its subsidiaries is subject to various risks similar to risks associated with the business of Exelon and its subsidiaries. Upon completion of the Merger, the combined

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company will be subject to these risks of PSEG and its subsidiaries. In addition, there are various risks associated with the proposed Merger including the following:

Exelon and PSEG could fail to complete the Merger for various reasons, which could have an adverse effect on Exelon.

Several events must occur before the Merger may be completed, such as the receipt of the required regulatory approvals and the satisfaction of various conditions to the obligations of each of Exelon and PSEG, including:

• the other party having performed in all material respects all agreements required to be performed by it under the Merger Agreement,

• the representations and warranties of the other party contained in the Merger Agreement being true and correct in all material respects,

• the absence of any material adverse effect having occurred to the other company since the date of the Merger Agreement and

• the approval by the NJBPU that the combined company will be able to recover Public Service Electric and Gas Company’s pension and other postretirement benefit expenses (as discussed in more detail below).

In addition, the Merger Agreement may be terminated at any time prior to completion of the Merger by mutual written consent of Exelon and PSEG, by either party if a governmental authority takes any final action prohibiting the Merger, by either party if a governmental authority approves the Merger but issues a burdensome order (as defined in the Merger Agreement), or by either party if the Merger is not completed by June 20, 2006. In addition, the Merger Agreement may be terminated by Exelon for various specific reasons, including a material breach of any agreement of PSEG in the Merger Agreement which would result in a closing condition to the Merger not being satisfied and which cannot be cured by PSEG within 30 days after written notice is given by Exelon. PSEG can terminate the Merger Agreement for various specific reasons, including a material breach of any agreement of Exelon in the Merger Agreement which would result in a closing condition to the Merger not being satisfied and which cannot be cured by Exelon within 30 days after written notice is given by PSEG. If the Merger were unable to be consummated, Exelon would be required to expense previously capitalized Merger costs, totaling $46 million at December 31, 2005, which would negatively impact its results of operations.

Exelon may be unable to successfully integrate PSEG’s operations or realize all of the synergies expected to be derived from the Merger.

The Merger involves the integration of two companies that previously operated independently. The difficulties of combining each company’s operations include:

• the necessity of coordinating geographically separated organizations, systems and facilities; and

• integrating personnel with diverse business backgrounds.

In addition, the integration of some of Exelon’s and PSEG’s operations will require regulatory approval.

Exelon recognizes that the process of integrating operations could cause an interruption of, or loss of momentum in, the activities of one or more of the combined company’s businesses. The diversion of management’s attention and any delays or difficulties encountered in connection with the Merger and the integration of the two companies’ operations could have an adverse effect on the business,

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financial condition, operating results and prospects of the combined company after the Merger, and could impair the combined company’s ability to realize the expected synergies and other anticipated benefits of the Merger.

The application of the purchase method of accounting will result in approximately $6 billion to $7 billion of additional goodwill, which could become impaired following completion of the Merger.

Under the purchase method of accounting, the total purchase price paid by Exelon in the Merger will be allocated to PSEG’s tangible and intangible assets and liabilities based on their fair values as of the date of completion of the Merger. The excess of the purchase price over those fair values will be recorded as goodwill. Exelon expects that the Merger will result in the creation of approximately $6 billion to $7 billion in goodwill based upon the assumptions as of the date of the completion of the Merger. As a result, upon completion of the Merger, the combined company will have approximately $10 billion to $11 billion in goodwill. To the extent the value of goodwill or intangibles becomes impaired, the combined company may be required to incur material charges relating to such impairment. Such a potential impairment charge could have a material impact on the combined company’s operating results.

The combined company may be unable to obtain permission from the NJBPU to recover Public Service Electric and Gas Company’s pension and other postretirement benefit expenses, which could have an adverse effect on its cash flow and results of operation.

Public Service Electric and Gas Company (PSE&G), a public utility subsidiary of PSEG, is permitted by its current NJBPU rate order to recover through its rates the amortized portion of its pension expenses and other postretirement benefit expenses associated with its pension and postretirement obligations. As a result of the application of the purchase method of accounting to these costs, the recognition of certain unrecognized pension and other postretirement benefit expenses will be accelerated and, as a result, will no longer be reflected in the calculation of pension and other postretirement benefit expenses that PSE&G’s current rate order permits it to recover. PSE&G estimates that it could have as much as $1.4 billion in unrecognized pension and other postretirement benefit expenses that it may be unable to recover following completion of the Merger unless it obtains approval from the NJBPU to permit continued recovery of those expenses in the manner the current rate order permits. Exelon and PSEG have made it a condition to completion of the Merger that PSE&G receive an order from the NJBPU permitting PSE&G to continue to recover the pension expenses as it did prior to completion of the Merger. PSE&G has requested such an order in the Merger approval proceeding, and no party has objected to the request for recovery, provided that the requested recovery of pension and postretirement expense would not be expected to increase rates above current levels. However, there is no assurance that PSE&G will receive such an order from NJBPU or that if it does receive such an order, it will be permitted in future rate proceedings to continue to recover these expenses. Failure to obtain or maintain the right to recover the pension and other postretirement benefit expenses would have an adverse effect on the combined company’s cash flow and results of operations.

Exelon will incur significant transaction and Merger-related integration costs in connection with the Merger.

Exelon expects to incur costs associated with consummating the Merger and integrating the operations of Exelon and PSEG, as well as approximately $41 million in transaction costs. The estimated $41 million of transaction costs incurred by Exelon will be included as a component of the purchase price for purposes of purchase accounting. The amount of transaction fees expected to be incurred is a preliminary estimate and subject to change. Exelon has estimated the integration costs

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associated with the Merger to be approximately $700 million over a period of four years, with approximately $400 million being incurred in the first full year of operations following completion of the Merger. These estimates may change, and additional unanticipated costs may be incurred in the integration of the businesses of the two companies. Although Exelon believes that the elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, will offset incremental transaction and Merger-related costs over time, it cannot give any assurance that this net benefit will be achieved in the near term, or at all.

Exelon and PSEG will be subject to business uncertainties and contractual restrictions while completion of the Merger is pending that could adversely affect their businesses.

Uncertainty about the effect of the Merger on employees and customers may have an adverse effect on Exelon and PSEG and, consequently, on the combined company. Although Exelon and PSEG have taken and will continue to take steps to reduce adverse effects, these uncertainties may impair Exelon’s and PSEG’s ability to attract, retain and motivate key personnel until the Merger is consummated and for a period of time thereafter, and could cause customers, suppliers and others that deal with Exelon and PSEG to seek to change existing business relationships with Exelon and PSEG. Employee retention may be particularly challenging during the pendency of the Merger, as employees may experience uncertainty about their future roles with the combined company. If, despite Exelon’s and PSEG’s retention efforts, key employees depart because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, the combined company’s business could be seriously harmed. In addition, the Merger Agreement restricts Exelon and PSEG from making certain acquisitions and taking other specified actions until the Merger occurs or the Merger Agreement terminates. These restrictions may prevent Exelon and PSEG from pursuing attractive business opportunities and making other changes to their businesses that may arise prior to completion of the Merger or termination of the Merger Agreement.

The combined company and its subsidiaries may be subject to adverse regulatory conditions following completion of the Merger.

Before the Merger may be completed, various approvals or consents must be obtained from various utility regulatory, antitrust and other authorities in the United States and in foreign jurisdictions. The governmental entities from which these approvals are required may fail to approve the Merger, impose conditions on completion of the Merger, or require changes to the terms of the Merger. These conditions or changes could have the effect of delaying completion of the Merger or imposing additional costs on or limiting the revenues of the combined company following the Merger, any of which might have a material adverse effect on the combined company following completion of the Merger.

On July 1, 2005, the FERC issued an order approving the Merger and the market concentration mitigation plan proposed by Exelon and PSEG. Exelon, PSEG and the combined company may incur significant expenses in completing the divestitures contemplated by the market concentration mitigation plan. In addition, they may have difficulty in successfully completing the divestitures for a variety of reasons and the amounts that may be realized from the divestitures will depend on market conditions that fluctuate. As a result, the pricing and other terms realized on the divestiture may be materially different from what is currently expected.

On September 13, 2005, PECO filed before the PAPUC a partial settlement regarding PECO’s distribution and transmission rates through 2010 and made other financial commitments contingent upon the approval of PECO’s application to the PAPUC related to the Merger. See “Partial Settlements Before the PAPUC” in ITEM 1. Business for further detail. The settlement and the Merger have received PAPUC approval but the settlement will not become effective unless the Merger is completed. The completion of this settlement will negatively impact the results of operations of PECO and the combined company.

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Under the combined company’s holding company structure, the payment of dividends to shareholders will be subject to the ability of its subsidiaries to pay dividends.

The combined company will be a holding company with no material assets other than the stock of its subsidiaries. Accordingly, all of the combined company’s operations will be conducted by its subsidiaries. The combined company’s ability to pay dividends on its common stock will depend on the payment to it of dividends by its operating subsidiaries. These subsidiaries’ payments of dividends to the combined company in turn depend on their results of operations and cash flows and other items impacting retained earnings. Under applicable law, PSE&G can pay dividends only from the amount of retained, undistributed or current earnings. Following completion of the Merger, a significant loss recorded at PSE&G may limit the dividends that PSE&G can distribute to Exelon. As a condition to approval of other utility mergers, the NJBPU has imposed dividends restrictions. Exelon can give no assurance that a similar restriction will not be imposed on PSE&G. In addition, PSEG Energy Holdings LLC and its subsidiaries are parties to debt agreements that restrict their ability to pay dividends, make cash distributions or otherwise transfer funds to PSEG, or after completion of the Merger, the combined company.

PSEG’s business is, and the combined company’s business will be, subject to extensive regulation that will affect operations and costs.

The combined company will be subject to regulation by FERC and the NRC, by Federal, state and local authorities under environmental laws and by state public utility commissions under laws regulating Exelon’s and PSEG’s distribution businesses, among others. See “Changes in ComEd’s and PECO’s terms and conditions of service, including its rates, are subject to regulatory approval proceedings that are contentious, lengthy and subject to appeal, which introduce time delays in effecting rate changes as well as uncertainty as to the ultimate result” above for further discussion. Additionally, the combined company will also be subject to additional risks currently applicable to PSEG as described below.

PSE&G’s New Jersey base rates for electric and gas distribution are subject to regulation by the NJBPU and are effective until a new base rate case is filed and concluded. In addition, limited categories of costs are recovered through adjustment charges that are periodically reset to reflect current costs. The inability to recover material costs not included in base rates or adjustment clauses could have an adverse effect on cash flow and financial position of the combined company.

PSEG Global LLC (PSEG Global) is a subsidiary of PSEG with rate-regulated electric and gas distribution facilities located in various foreign jurisdictions. Governmental authorities establish rates charged to customers. While these rates are designed to cover all operating costs and provide a return, considerable fiscal and cash uncertainties in certain countries due to local regulation or economic, political and social crisis could have an adverse impact. In addition, future rates may not be adequate to provide cash flow to pay principal and interest on the debt of PSEG Global’s subsidiaries and affiliates or to enable its subsidiaries and affiliates to comply with the terms of debt agreements.

The combined company’s generation business may incur additional costs and liabilities due to its ownership and operation of additional nuclear facilities.

Following completion of the Merger, it is expected that, prior to giving effect to any divestitures required by governmental authorities to complete the Merger and prior to implementing the combined company’s anticipated strategy of divesting assets that do not meet the strategic objectives of the combined company, approximately 46% of the combined company’s owned generation capacity will be nuclear and the combined company will own approximately 20% of the nuclear generation capacity in the United States. To the extent there are divestitures of fossil assets, such as described in “The

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combined company may be subject to adverse regulatory conditions following completion of the Merger” above, the percentage of the combined company’s owned generation capacity which is nuclear will increase. Accordingly, the combined company will have greater exposure to risks that adversely affect the nuclear generation industry compared to other companies in the utility industry. See “Generation’s financial performance may be negatively affected by liabilities arising from its ownership and operation of nuclear facilities” above for further discussion.

The combined company’s generation business may incur additional costs and liabilities and be exposed to volatility as a result of expanded participation in the wholesale energy markets.

Generation and PSEG, and the combined company, will sell electricity in the wholesale energy markets. Generation and PSEG are subject to many of the same risks in the wholesale energy markets. See “Generation is exposed to price fluctuations and other risks of the wholesale power market that are beyond its control, which may negatively impact its results of operations” above for further discussion. Following completion of the proposed Merger, the combined company will be subject to additional risks associated with participation in the wholesale energy markets as described below.

The trading business of the combined company after the Merger will be required to meet credit quality standards. If the generation business of the combined company were to lose its investment grade credit rating or otherwise fail to satisfy the credit standards of trading counterparties, it would be required under trading agreements to provide collateral in the form of letters of credit or cash, which may materially adversely affect the liquidity of the combined company. See “Generation is exposed to price fluctuations and other risks of the wholesale power market that are beyond its control, which may negatively impact its results of operations” above for further discussion. If PSEG Power had lost its investment grade credit rating as of December 31, 2005, it would have been required to provide approximately $916 million in additional collateral. Due to the increased size of the combined company’s generation business, a trading counterparty that does business with both Generation and PSEG Power might impose credit limits or other credit quality standards on the combined company’s generation business that are more restrictive than would otherwise be applicable to Generation and PSEG Power as separate operations.

The IRS might successfully challenge certain leveraged lease transactions entered into by PSEG, which could have a material adverse impact on the combined company’s operating results.

From 1996 through 2002, PSEG, through its indirect wholly owned subsidiary, PSEG Resources, entered into a number of leveraged lease transactions in the ordinary course of business. Certain of those transactions that were previously entered into are similar to a type that the IRS subsequently announced its intention to challenge, and PSEG understands that similar transactions entered into by other companies have been the subject of review and challenge by the IRS. The IRS is presently reviewing the tax returns of PSEG and its subsidiaries for tax years 1997 through 2000, years when Resources entered into some of these transactions.

On September 27, 2005, the IRS proposed to disallow PSEG’s deductions associated with certain of these leveraged leases which have been designated by the IRS as listed transactions. Other lease transactions within the audit period are still under the IRS’s review. The IRS may propose additional disallowances in the future. If deductions associated with these lease transactions entered into by PSEG are successfully challenged by the IRS, it could have a material adverse impact on the combined company’s financial position, results of operations and net cash flows and could impact future returns on these transactions.

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If the tax benefits associated with the above referenced lease transactions were completely disallowed by the IRS, approximately $660 million of deferred tax liabilities that have been recorded under leveraged lease accounting through December 31, 2005 could become currently payable. In addition, interest expense of approximately $86 million, after tax, and penalties could be assessed.

The FASB is currently considering a modification to GAAP for leveraged leases. Under present GAAP, a tax settlement with the IRS that results in a change in the timing of tax liabilities would not require an accounting repricing of the lease investment. As such, income from the lease would continue to accrue at the original economic yield computed for the lease and there would be no write-down of the lease investment.

The proposal concerning leveraged leases would require a lessor to perform a recalculation of a leveraged lease when there is a change in the timing of the realization of tax benefits generated by the lease. It would also require a lessor to re-evaluate classification as a leveraged lease when a recalculation of the lease is performed. If implemented in its present form, the impact of this proposal on the combined company could be material.

Because a portion of the combined company’s business will be conducted outside the United States, adverse international developments could negatively impact its business.

Following completion of the Merger and prior to implementing the combined company’s anticipated strategy of divesting assets that do not meet the strategic objectives of the combined company, it is expected that revenues generated from sources outside the United States and assets located outside the United States will each be less than 5% of the total combined company, most of which will be held by and generated from PSEG Global.

The economic and political conditions in certain countries where PSEG Global has interests present risks that may be different from, or more extensive than, those found in the United States including:

• foreign currency fluctuations;

• risks of war;

• expropriation;

• nationalization;

• renegotiation or nullification of existing contracts; and

• changes in law or tax policy.

Changes in the legal environment in foreign countries in which PSEG Global has investments could make it more difficult to obtain non-recourse project refinancing on suitable terms and could impair PSEG Global’s ability to enforce its rights under agreements relating to such projects. In addition, such changes could make it more difficult for the combined company to pursue an accelerated strategy of selling certain of PSEG Global’s investments that no longer meet the strategic objectives of the combined company.

Operations in foreign countries also present risks associated with currency exchange and convertibility, inflation and repatriation of earnings. In countries in which PSEG Global operates in the future, economic and monetary conditions and other factors could affect PSEG Global’s ability to convert its cash distributions to United States dollars or other freely convertible currencies, or to move funds offshore from these countries. Furthermore, the central bank of any of these countries may have the authority to suspend, restrict or otherwise impose conditions on foreign exchange transactions or to

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approve distributions to foreign investors. Although PSEG Global generally seeks to structure purchase power contracts and other project revenue agreements to provide for payments to be made in, or indexed to, United States dollars or a currency freely convertible into United States dollars, its ability to do so in all cases may be limited.

The combined company’s results of operations may be affected by its ability to divest unprofitable or under-performing businesses.

The combined company will pursue opportunities to sell businesses and assets that either do not meet the strategic objectives of the combined company or are unprofitable. The combined company may incur significant expenses in divesting these businesses. The combined company also may be unable to successfully implement this strategy for a number of reasons, including an inability to locate appropriate buyers or to negotiate acceptable terms for the transactions. In addition, the amounts that the combined company may realize 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. Timing of any divestitures may positively or negatively affect the combined company’s results of operations and cash flows.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Exelon, ComEd, PECO and Generation

None.

ITEM 2. PROPERTIES

ComEd and PECO

The electric substations and a portion of the transmission rights of way are located on property owned by ComEd and PECO. 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 but without examination of underlying land titles, have been obtained.

Transmission and Distribution

ComEd’s and PECO’s higher voltage electric transmission lines owned and in service at December 31, 2005 were as follows:

	Voltage (Volts)	Circuit Miles
ComEd	765,000	90
	345,000	2,621
	138,000	2,866
	69,000	149
PECO	500,000	188	(a)
	220,000	541
	132,000	156
	66,000	153

(a) In addition, PECO has a 22.00% ownership of 127 miles of 500,000 voltage lines located in Pennsylvania and a 42.55% ownership of 151 miles of 500,000 voltage lines located in Delaware and New Jersey.

ComEd’s electric distribution system includes 43,082 circuit miles of overhead lines and 33,804 cable miles of underground lines. PECO’s electric distribution system includes 12,873 circuit miles of overhead lines and 15,201 cable miles of underground lines.

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Gas

The following table sets forth PECO’s gas pipeline miles at December 31, 2005:

	Pipeline Miles
Transmission	31
Distribution	6,528
Service piping	5,377
Total	11,936

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 their respective properties by fire or other perils, subject to certain exceptions. For its insured losses, ComEd and PECO are self-insured to the extent that any losses are within the policy deductible or 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, 2005. The table does not include properties held by equity method investments:

Station	Location	No. of Units	Percent Owned (a)	Primary Fuel Type	Primary Dispatch Type(e)	Net Generation Capacity (MW) (b)
Nuclear(c)
Braidwood	Braidwood, IL	2		Uranium	Base-load	2,360
Byron	Byron, IL	2		Uranium	Base-load	2,336
Clinton	Clinton, IL	1		Uranium	Base-load	1,030
Dresden	Morris, IL	2		Uranium	Base-load	1,742
LaSalle	Seneca, IL	2		Uranium	Base-load	2,288
Limerick	Limerick Twp., PA	2		Uranium	Base-load	2,302
Oyster Creek	Forked River, NJ	1		Uranium	Base-load	625
Peach Bottom	Peach Bottom Twp., PA	2	50.00	Uranium	Base-load	1,135	(d)
Quad Cities	Cordova, IL	2	75.00	Uranium	Base-load	1,232	(d)
Salem	Hancock’s Bridge, NJ	2	42.59	Uranium	Base-load	969	(d)
Three Mile Island	Londonderry Twp, PA	1		Uranium	Base-load	837
						16,856

(continued on next page)

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Station	Location	No. of Units	Percent Owned (a)	Primary Fuel Type	Primary Dispatch Type(e)	Net Generation Capacity (MW) (b)
Fossil (Steam Turbines)
Conemaugh	New Florence, PA	2	20.72	Coal	Base-load	352	(d)
Cromby 1	Phoenixville, PA	1		Coal	Base-load	144
Cromby 2	Phoenixville, PA	1		Oil/Gas	Intermediate	201
Eddystone 1, 2	Eddystone, PA	2		Coal	Base-load	588
Eddystone 3, 4	Eddystone, PA	2		Oil/Gas	Intermediate	760
Fairless Hills	Falls Twp, PA	2		Landfill Gas	Peaking	60
Handley 4, 5	Fort Worth, TX	2		Gas	Peaking	916
Handley 3	Fort Worth, TX	1		Gas	Intermediate	400
Keystone	Shelocta, PA	2	20.99	Coal	Base-load	358	(d)
Mountain Creek 2, 6, 7	Dallas, TX	3		Gas	Peaking	273
Mountain Creek 8	Dallas, TX	1		Gas	Intermediate	550
New Boston 1	South Boston, MA	1		Gas	Intermediate	353
Schuylkill	Philadelphia, PA	1		Oil	Peaking	166
Wyman	Yarmouth, ME	1	5.89	Oil	Intermediate	36	(d)
						5,157
Fossil (Combustion Turbines)
Chester	Chester, PA	3		Oil	Peaking	39
Croydon	Bristol Twp., PA	8		Oil	Peaking	384
Delaware	Philadelphia, PA	4		Oil	Peaking	56
Eddystone	Eddystone, PA	4		Oil	Peaking	60
Falls	Falls Twp., PA	3		Oil	Peaking	51
Framingham	Framingham, MA	3		Oil	Peaking	30
LaPorte	Laporte, TX	4		Gas	Peaking	160
Medway	West Medway, MA	3		Oil	Peaking	110
Moser	Lower Pottsgrove Twp., PA	3		Oil	Peaking	51
New Boston	South Boston, MA	1		Gas	Peaking	13
Pennsbury	Falls Twp., PA	2		Landfill Gas	Peaking	6
Richmond	Philadelphia, PA	2		Oil	Peaking	96
Salem	Hancock’s Bridge, NJ	1	42.59	Oil	Peaking	16	(d)
Schuylkill	Philadelphia, PA	2		Oil	Peaking	30
Southeast Chicago	Chicago, IL	8	72.00	Gas	Peaking	312	(f)
Southwark	Philadelphia, PA	4		Oil	Peaking	52
						1,466
Fossil (Internal Combustion/Diesel)
Conemaugh	New Florence, PA	4	20.72	Oil	Peaking	2	(d)
Cromby	Phoenixville, PA	1		Oil	Peaking	3
Delaware	Philadelphia, PA	1		Oil	Peaking	3
Keystone	Shelocta, PA	4	20.99	Oil	Peaking	2	(d)
Schuylkill	Philadelphia, PA	1		Oil	Peaking	3
						13
Hydroelectric
Conowingo	Harford Co. MD	11		Hydroelectric	Base-load	536
Muddy Run	Lancaster, PA	8		Hydroelectric	Intermediate	1,071
						1,607
Total		126				25,099

(a) 100%, unless otherwise indicated.

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

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

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

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(e) Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system, and consequently produce electricity at an essentially constant rate. Intermediate units are plants that normally operate to take load of a system during the day time higher load hours, and consequently produce electricity by cycling on and off daily. Peaking units are plants that usually house low-efficiency, quick response steam units, gas turbines, diesels, or pumped-storage hydroelectric equipment normally used during the maximum load periods.

(f) Includes the total capacity of the Southeast Chicago Energy Project. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for additional information.

The net generation 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 additional information regarding nuclear insurance of generating facilities, see ITEM 1. Business—Generation. For its insured losses, Generation is self-insured to the extent that any losses are within the property deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on Generation’s consolidated financial condition or results of operations.

ITEM 3. LEGAL PROCEEDINGS

Exelon, ComEd, PECO and Generation are parties to various regulatory proceedings in the ordinary course of business. They are also parties to regulatory proceedings in connection with the Merger. Other material legal and regulatory proceedings are summarized below.

Exelon, PECO and Generation

PJM Billing Dispute.In December 2004, Exelon filed a complaint against PJM and PPL Electric with the FERC alleging that PJM had overcharged Exelon from April 1998 through May 2003 as a result of a billing error. Specifically, the complaint alleges that PJM mistakenly identified PPL Electric’s Elroy substation transformer as belonging to Exelon and that, as a consequence, during times of congestion, Exelon’s bills for transmission congestion from PJM erroneously reflected energy that PPL Electric took from the Elroy substation and used to serve PPL Electric’s load. The complaint requested the FERC, among other things, to direct PPL Electric to refund to PJM $39.1 million, plus interest of approximately $8 million, and for PJM to refund these same amounts to Exelon.

On September 14, 2005, Exelon and PPL Electric filed a proposed settlement of this matter with the FERC. If the settlement is approved by the FERC, Exelon will receive a total of $40.5 million, plus interest, over the next four years from two funding sources: (a) $33 million from PPL Electric; and (b) $7.5 million from PJM market participants. It is anticipated that approximately 75% and 25% of the proposed settlement will be received by Generation and PECO, respectively. Both charges will be collected and paid by PJM over a four-year period following FERC approval of the settlement with interest on the unpaid principal accruing over the collection and payment period. As Exelon is a market participant in PJM, if this settlement is approved by the FERC, the net amount of the settlement to be received by Exelon will be reduced by Exelon’s portion of the $7.5 million described above.

Pending FERC approval of the settlement, Exelon has not recorded any receivables associated with this matter.

ComEd

Illinois Procurement Filing. On January 24, 2006, the ICC, by a unanimous vote, approved a reverse-auction competitive bidding process for procurement of power by ComEd for the time period

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after 2006. Several parties have indicated that they will petition the ICC for rehearing and will challenge the ICC decision in court. ComEd has also petitioned for rehearing of the ICC decision on certain issues, but that petition was denied by the ICC on February 8, 2006. It is also possible that interested parties could introduce legislation in Illinois in attempt to modify the procurement process or the rates that ComEd may charge consumers for the power ComEd purchases to meet the needs of consumers. The Illinois General Assembly has held hearings concerning generation procurement after 2006, and it may take action on this issue. See Note 4 of Exelon’s Notes to Consolidated Financial Statements for additional information

Illinois Rate Case. On August 31, 2005, ComEd filed a rate case with the ICC, which seeks, among other things, to allocate the costs of delivering electricity and to adjust ComEd’s rates for delivering electricity effective January 2, 2007 (Rate Case). Several intervenors in the Rate Case, including the ICC staff and the Illinois Attorney General, have suggested, and provided testimony, that ComEd’s rates should actually be reduced. The commodity component of ComEd’s rates will be established by the reverse-auction process in accordance with the ICC order in the Procurement Case, assuming the ICC order on this matter is upheld upon appeal. The results of the Rate Case are not expected to be known until at least the third quarter of 2006.

PECO and Generation

Real Estate Tax Appeals.PECO and Generation each have been challenging real estate taxes assessed on nuclear plants. 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 2004, also regarding the valuation of its Limerick and Peach Bottom plants, Quad Cities Station (Rock Island County, IL), Three Mile Island Nuclear Station (Dauphin County, PA) (TMI) and Oyster Creek Station (Forked River, NJ). PECO and Generation have reached settlements with the taxing authorities over the Limerick real estate assessments for 1998 and 1999. Pursuant to the settlement agreement, all Limerick tax appeals were dismissed by the state court, and PECO has agreed to an additional payment of approximately $3 million for the two PURTA years and Generation has agreed to make additional payments in lieu of taxes for years 2005 through 2008. As a result of the Limerick settlement, PECO reduced its real estate tax reserve balance by $6 million in the first quarter of 2005. In addition, Generation has reached a settlement with the taxing authorities over the TMI real estate assessment, which has been approved by the state court. As a result of the TMI settlement, Generation reduced its real estate tax reserve balance by $6 million in the first quarter of 2005. Generation reached an agreement with the taxing authorities for all years under appeal for the Quad Cities station and the court approved the agreement on December 9, 2005. Generation also recently reached an agreement with the taxing authorities for all years under appeal for the Oyster Creek station an order implementing Oyster Creek’s property tax settlement was entered on December 16, 2005. In addition, on December 22, 2005, Generation reached an agreement for the 2005 tax year with the taxing authorities for LaSalle County Station, and is working towards court approval by the end of the first quarter of 2006.

PECO and Generation believe their reserve balances for other exposures associated with real estate taxes as of December 31, 2005 and 2004 reflect the probable expected outcome of the litigation and appeals proceedings in accordance with SFAS No. 5. The ultimate outcome of such matters, however, could result in unfavorable or favorable adjustments to the consolidated financial statements of Exelon, PECO and Generation and such adjustments could be material.

Reverse-Employment Discrimination Claim. On April 4, 2005, one employee of PECO and four employees of Generation commenced suit in the United States District Court for the Eastern District of

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Pennsylvania, alleging that they were subjected to a practice of reverse-employment discrimination which denied promotional opportunities to older white male employees, purportedly in violation of various Federal antidiscrimination statutes and the Pennsylvania Human Relations Act. The plaintiffs filed the action individually and on behalf of a putative class that includes all white males currently or previously employed with any Exelon companies in the United States who were at least 40 years old on April 4, 2003 and who either applied for or were eligible to apply for supervisory positions in March 2003 and thereafter, continuing to the present day, and were not selected for these positions. The defendants have filed an answer denying all liability and are proceeding with discovery pertaining to the class allegations and the named plaintiffs’ individual claims. In December 2005, the Court ordered the case to be suspended until April 3, 2006 while the parties attempt to resolve this matter through non-binding mediation. As this case is in the early stages, Exelon cannot predict the outcome; however, Exelon does not expect this claim to have a material adverse effect on Exelon’s financial condition, results of operations or cash flows.

Generation

Cotter Corporation Litigation. During 1989 and 1991, actions were brought in Federal and state courts in Colorado against ComEd and its subsidiary, 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. 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 any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred by ComEd to Generation.

Several of the actions resulted in nominal jury verdicts or were settled or dismissed. One action resulted in an award for the plaintiffs of 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. In October 2004, a settlement of the claims of all Cotter plaintiffs was reached and approved by the Federal District Court in Colorado. This settlement amount approximated Generation’s reserve for this matter. Settlements with the two primary Cotter insurers were also concluded, under which they paid Generation approximately $20 million, which covered the amount previously reserved as well as certain other costs incurred by Generation related to this matter. Neither of these settlements affects the environmental liability associated with the West Lake Landfill. The EPA has advised Cotter that it is potentially liable in connection with radiological contamination at the West Lake Landfill in Missouri. 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 estimated costs of the anticipated remediation strategy for the site range up to $22 million. Once a remedy is selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. For additional information, see ITEM 1. Business—Environmental Regulation.

Asbestos Personal Injury Claims.Like many other industrial companies, Generation is a defendant in personal injury actions related to asbestos exposure in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The vast majority of these asbestos-related bodily injury claims allege a variety of lung-related diseases based on alleged exposure to asbestos by former third-party contractors involved in the original construction or maintenance of the facilities. The construction of these facilities primarily occurred between 1950 and 1975. Generation does not have significant asbestos-related bodily injury claims occurring after 1980.

As part of the 2001 restructuring in which Generation purchased ComEd’s and PECO’s energy- producing facilities, Generation assumed all of ComEd’s and PECO’s current and future benefits and

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liabilities associated with these facilities. Based on the receipt of asbestos-related bodily injury claims during 2002, 2003 and 2004, where previously an insignificant number of claims were received and corresponding expenses were recorded, Generation engaged independent actuaries to determine if a reasonable estimate of future losses could be made based on historical claims data and other available information. Based on the currently available volume and diversity of historical claim and payment data, the actuaries determined that a reasonable estimate could be prepared and, accordingly, Generation engaged the actuaries to calculate an estimate of future losses. In the second quarter of 2005, based on the actuaries’ analyses, management’s review of current and expected losses and the view of counsel regarding the assumptions used in estimating the future losses, Generation recorded an undiscounted $43 million pre-tax charge for its estimated portion of all estimated future asbestos-related personal injury claims estimated to be presented through 2030. This amount does not include estimated legal costs associated with handling these matters, which could be material. Exelon management determined that it was not reasonable to estimate future asbestos-related personal injury claims past 2030 based on only three years of historical claims data and the significant amount of judgment required to estimate this liability. In calculating future losses, management and the actuaries made various assumptions, including, but not limited to, the overall number of future claims estimated through the use of actuarial models, Exelon’s estimated portion of future settlements and obligations, the distribution of exposure sites, the anticipated future mix of diseases that relate to asbestos exposure and the anticipated levels of awards made to plaintiffs. Exelon’s recent history of successfully defending itself in court cases for asbestos-related bodily injury claims was qualitatively considered in determining this estimate.

The amounts recorded by Generation for estimated future asbestos-related bodily injury claims are based upon known facts at the time the report was prepared. Projecting future events, such as the number of new claims to be filed each year and the average cost of disposing of claims, as well as the numerous uncertainties surrounding asbestos-related litigation in the United States, could cause the actual costs to be higher or lower than projected. While it is not possible to predict the ultimate outcome of the asbestos-related claims and settlements, management believes, after consultation with counsel, that resolution of these matters is not expected to have a material adverse effect on Exelon’s or Generation’s results of operations and financial position. Management cautions, however, that estimates for asbestos-related bodily injury cases and settlements are difficult to predict and may be influenced by many factors. Accordingly, these matters, if resolved in a manner different from the estimate, could have a material effect on Exelon’s or Generation’s results of operations, financial position and cash flow.

The $43 million pre-tax charge was recorded as part of operating and maintenance expense on Generation’s Consolidated Statement of Income in 2005 and reduced net income by $27 million. At December 31, 2005 and 2004, Exelon had approximately $50 million and $10 million, respectively, reserved in total for asbestos-related bodily injury claims. As of December 31, 2005, approximately $9 million of this amount relates to 120 open claims presented to Generation, while the remaining $41 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2030. Exelon plans to obtain annual updates of the estimate of future losses. On a quarterly basis, Exelon monitors actual experience against the number of forecasted claims to be received and expected claim payments.

Oil Spill Liability Trust Fund Claim. In December 2004, the two Salem nuclear generation units were taken offline due to an oil spill from a tanker in the Delaware River near the facilities. The units, which draw water from the river for cooling purposes, were taken offline for approximately two weeks to avoid intake of the spilled oil, resulting in lost sales from the plant. Generation and PSEG have filed a joint claim for losses and damages with the Oil Spill Liability Trust Fund. As this matter represents a contingent gain, Generation has recorded no income resulting from this claim. However, Generation’s management believes it is reasonably possible that damages and losses will be recovered and that

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Generation’s portion of the estimated proceeds arising from the claim will be approximately $25 million. Exelon expects this matter to be resolved in 2006.

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. Exelon, ComEd, PECO and Generation maintain accruals for such costs that are probable of being incurred and subject to reasonable estimation. The ultimate outcomes of such matters, as well as the matters discussed above, are uncertain and may have a material adverse effect on their respective financial condition, results of operations or cash flows.

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

Exelon, ComEd, PECO and Generation

None.

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PART II

(Dollars in millions except per share data, unless otherwise noted)

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Exelon

Exelon’s common stock is listed on the New York Stock Exchange. As of January 31, 2006, there were 667,233,091 shares of common stock outstanding and approximately 160,754 shareholders of common stock of record.

The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis:

	2005								2004
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter		Fourth Quarter		Third Quarter		Second Quarter		First Quarter
High price	$	56.00	$	57.46	$	52.01	$	47.18	$	44.90	$	37.90	$	34.89	$	34.43
Low price		46.62		49.60		44.14		41.77		36.73		32.69		30.92		32.18
Close		53.14		53.44		51.33		45.89		44.07		36.69		33.29		34.43
Dividends		0.400		0.400		0.400		0.400		0.400		0.305		0.275		0.275

On July 22, 2005, Exelon’s shareholders approved the issuance of Exelon common stock as contemplated by the Agreement and Plan of Merger, dated December 20, 2004, between Exelon and PSEG. Effective October 24, 2005, Exelon’s Amended and Restated Articles of Incorporation were amended to increase the number of authorized shares of Exelon common stock from 1.2 billion to 2 billion.

The attached table gives information on a monthly basis regarding purchases made by Exelon of its common stock.

Period	Total Number of Shares Purchased (a)	Average Price Paid per Share		Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs(b)	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
October 1—October 31, 2005	1,178	$	53.44	—	(b	)
November 1—November 30, 2005	1,943,670		51.82	1,928,900	(b	)
December 1—December 31, 2005	3,250		53.50	—	(b	)
Total	1,948,098		51.83	—	(b	)

(a) Shares other than those purchased as a part of a publicly announced plan primarily represent restricted shares surrendered by employees to satisfy tax obligations arising upon the vesting of restricted shares and shares repurchased from an executive upon retirement from Exelon.

(b) In April 2004, Exelon’s Board of Directors approved a discretionary share repurchase program that allows Exelon to repurchase shares of its common stock on a periodic basis in the open market. The share repurchase program is intended to mitigate, in part, the dilutive effect of shares issued under Exelon’s employee stock option plan and Exelon’s Employee Stock Purchase Plan (ESPP). The aggregate shares of common stock repurchased pursuant to the program cannot exceed the economic benefit received after January 1, 2004 due to stock option exercises and share purchases pursuant to Exelon’s ESPP. The economic benefit consists of direct cash proceeds from purchases of stock and tax benefits associated with exercises of stock options. The share repurchase program has no specified limit and no specified termination date.

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ComEd

As of January 31, 2006, there were outstanding 127,016,519 shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were held by Exelon. At January 31, 2006, in addition to Exelon, there were 273 holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.

PECO

As of January 31, 2006, 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 January 31, 2006, Exelon held the entire membership interest in Generation.

Exelon, ComEd, PECO and Generation

Dividends

Under applicable Federal law, ComEd, PECO and Generation can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at ComEd, PECO or Generation may limit the dividends that these companies can distribute to Exelon.

Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “[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, 2005, Exelon had retained earnings of $3.2 billion, which includes ComEd’s retained deficit of $(81) million consisting of $1,099 million of retained earnings appropriated for future dividends offset by unappropriated deficit of $(1,180) million, PECO’s retained earnings of $649 million and Generation’s undistributed earnings of $1,002 million.

PECO’s Articles of Incorporation prohibit payment of any dividend on, or other distribution to the holders of, common stock if, after giving effect thereto, the capital of PECO represented by its common stock together with its retained earnings is, in the aggregate, less than the involuntary liquidating value of its then outstanding preferred stock. At December 31, 2005, such capital was $2.8 billion and amounted to about 32 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 PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; 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).

The following table sets forth Exelon’s quarterly cash dividends per share paid during 2005 and 2004:

	2005								2004
(per share)	4th Quarter		3rd Quarter		2nd Quarter		1st Quarter		4th Quarter		3rd Quarter		2nd Quarter		1st Quarter
Exelon	$	0.400	$	0.400	$	0.400	$	0.400	$	0.400	$	0.305	$	0.275	$	0.275

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

	2005								2004
(in millions)	4th Quarter		3rd Quarter		2nd Quarter		1st Quarter		4th Quarter		3rd Quarter		2nd Quarter		1st Quarter
ComEd	$	146	$	107	$	107	$	138	$	137	$	113	$	104	$	103
PECO		122		116		116		115		115		96		90		90
Generation		108		430		80		239		335		61		55		54

In July 2004, the Exelon Board of Directors approved a policy of targeting a dividend payout ratio of 50% to 60% of ongoing earnings. On January 24, 2006, the Exelon Board of Directors declared a regular quarterly dividend of $0.40 per share on Exelon’s common stock. The dividend is payable on March 10, 2006, to shareholders of record of Exelon at 5:00 p.m. Eastern Standard Time on February 15, 2006.

The Board of Directors of Exelon also declared a regular quarterly dividend of $0.40 per share on Exelon’s common stock for the second quarter of 2006. The dividend is payable on June 10, 2006, to shareholders of record of Exelon at 5:00 p.m. Eastern Standard Time on May 15, 2006.

The Board of Directors of Exelon has also declared an additional dividend payable within 30 days after closing of the Merger if the Merger closes after February 15, 2006 and on or before May 15, 2006. The dividend will be pro-rated, with shareholders receiving $0.00449 per share per day from February 15, 2006 to the closing of the Merger. This pro rata dividend is equivalent to $0.40 per share for the full quarter. If the Merger is not closed on or before May 15, 2006, the Board of Directors of Exelon expects to declare and pay a similar pro rata dividend for the period after May 15, 2006.

The Board of Directors of Exelon also changed its policy for dividend record and payment dates that will take effect after the closing of the Merger. Currently, dividend record dates are the fifteenth day of the second month of the quarter, and payment dates are the tenth day of the third month of the quarter. After the closing of the Merger, when the dividend is increased as required by the Merger Agreement, the record date will be the eighth day of the third month of a quarter, and the payment date will be the last business day of the third month of a quarter. The Board expects that there will be another pro-rated dividend for the period from the Merger closing date to the first regular record date under the new dividend schedule. This post-closing pro-rated dividend will be calculated at the increased dividend rate and will be paid on the first regular payment date under the new dividend schedule. The use of pro-rated dividends is intended to keep shareholders whole with respect to their dividends.

ITEM 6. SELECTED FINANCIAL DATA

Exelon

The selected financial data presented below has been derived from the audited consolidated financial statements of Exelon. This data is qualified in its entirety by reference to and should be read in conjunction with Exelon’s Consolidated Financial Statements and Management’s Discussion and Analysis of Financial Condition and Results of Operation included in ITEM 7 of this Report on Form 10-K.

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	For the Years Ended December 31,
in millions, except for per share data	2005			2004			2003			2002			2001
Statement of Income data:
Operating revenues	$	15,357		$	14,133		$	15,148		$	14,060		$	13,978
Operating income		2,724			3,499			2,409			3,280			3,406
Income from continuing operations	$	951		$	1,870		$	892		$	1,690		$	1,448
Income (loss) from discontinued operations		14			(29	)		(99	)		(20	)		(32	)
Income before cumulative effect of changes in accounting principles		965			1,841			793			1,670			1,416
Cumulative effect of changes in accounting principles (net of income taxes)		(42	)		23			112			(230	)		12
Net income(a), (b)	$	923		$	1,864		$	905		$	1,440		$	1,428
Earnings per average common share (diluted):
Income from continuing operations	$	1.40		$	2.79		$	1.36		$	2.60		$	2.24
Income (loss) from discontinued operations		0.02			(0.04	)		(0.15	)		(0.03	)		(0.05	)
Income before cumulative effect of changes in accounting principles		1.42			2.75			1.21			2.57			2.19
Cumulative effect of changes in accounting principles (net of income taxes)		(0.06	)		0.03			0.17			(0.35	)		0.02
Net income	$	1.36		$	2.78		$	1.38		$	2.22		$	2.21
Dividends per common share	$	1.60		$	1.26		$	0.96		$	0.88		$	0.91
Average shares of common stock outstanding—diluted		676			669			657			649			645

(a) Change between 2005 and 2004 is primarily due to the goodwill impairment charge of $1.2 billion in 2005.

(b) Change between 2004 and 2003 is primarily due to the impairment of Boston Generating, LLC long-lived assets of $945 million in 2003.

	December 31,
in millions	2005		2004		2003		2002		2001
Balance Sheet data:
Current assets	$	4,637	$	3,880	$	4,524	$	4,096	$	3,707
Property, plant and equipment, net		21,981		21,482		20,630		17,957		14,665
Noncurrent regulatory assets		4,386		4,790		5,226		5,546		5,774
Goodwill(a)		3,475		4,705		4,719		4,992		5,335
Other deferred debits and other assets		7,910		7,867		6,800		5,249		5,460
Total assets	$	42,389	$	42,724	$	41,899	$	37,840	$	34,941
Current liabilities	$	6,563	$	4,836	$	5,683	$	5,845	$	4,342
Long-term debt, including long-term debt to financing trusts		11,760		12,148		13,489		13,127		12,879
Regulatory liabilities		2,170		2,204		1,891		486		225
Other deferred credits and other liabilities		12,683		13,918		12,246		9,968		8,749
Minority interest		1		42		—		77		31
Preferred securities of subsidiaries(a)		87		87		87		595		613
Shareholders’ equity		9,125		9,489		8,503		7,742		8,102
Total liabilities and shareholders’ equity	$	42,389	$	42,724	$	41,899	$	37,840	$	34,941

(a) Change between 2005 and 2004 is primarily due to the goodwill impairment charge of $1.2 billion in 2005.

(b) Due to the adoptions of FIN 46 and FIN 46-R in 2003, the mandatorily redeemable preferred securities of ComEd and PECO were reclassified as long-term debt to financing trusts in 2003.

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ComEd

The selected 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 Operation included in ITEM 7 of this Report on Form 10-K.

	For the Years Ended December 31,
(in millions)	2005			2004		2003		2002		2001
Statement of Income data:
Operating revenues	$	6,264		$	5,803	$	5,814	$	6,124	$	6,206
Operating income (loss)		(12	)		1,617		1,567		1,766		1,594
Income (loss) before cumulative effect of changes in accounting principles	$	(676	)	$	676	$	702	$	790	$	607
Cumulative effect of a change in accounting principle (net of income taxes)		(9	)		—		5		—		—
Net income (loss)(a)	$	(685	)	$	676	$	707	$	790	$	607
	December 31,
(in millions)	2005			2004		2003		2002		2001
Balance Sheet data:
Current assets	$	1,024		$	1,196	$	1,313	$	1,049	$	1,025
Property, plant and equipment, net		9,906			9,463		9,096		8,689		8,243
Goodwill, net(a)		3,475			4,705		4,719		4,916		4,902
Other deferred debits and other assets		2,806			2,077		2,837		1,662		1,682
Total assets	$	17,211		$	17,441	$	17,965	$	16,316	$	15,852
Current liabilities	$	2,308		$	1,764	$	1,557	$	2,023	$	1,797
Long-term debt, including long-term debt to financing trusts(b)		3,541			4,282		5,887		5,268		5,850
Regulatory liabilities		2,170			2,204		1,891		486		225
Other deferred credits and other liabilities		2,796			2,451		2,288		2,451		2,568
Mandatorily redeemable preferred securities of subsidiary trusts(b)		—			—		—		330		329
Shareholders’ equity		6,396			6,740		6,342		5,758		5,083
Total liabilities and shareholders’ equity	$	17,211		$	17,441	$	17,965	$	16,316	$	15,852

(a) Change between 2005 and 2004 is primarily due to the goodwill impairment charge of $1.2 billion in 2005.

(b) Due to the adoption of FIN 46-R in 2003, the mandatorily redeemable preferred securities were reclassified as long-term debt to financing trusts as of December 31, 2003.

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PECO

The selected 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 Operation included in ITEM 7 of this Report on Form 10-K.

	For the Years Ended December 31,
(in millions)	2005			2004		2003		2002		2001
Statement of Income data:
Operating revenues	$	4,910		$	4,487	$	4,388	$	4,333	$	3,965
Operating income		1,049			1,014		1,056		1,093		999
Income before cumulative effect of a change in accounting principle	$	520		$	455	$	473	$	486	$	425
Cumulative effect of a change in accounting principle (net of income taxes)		(3	)		—		—		—		—
Net income	$	517		$	455	$	473	$	486	$	425
Net income on common stock	$	513		$	452	$	468	$	478	$	415
	December 31,
(in millions)	2005			2004		2003		2002		2001
Balance Sheet data:
Current assets	$	795		$	727	$	659	$	898	$	785
Property, plant and equipment, net		4,471			4,329		4,256		4,159		4,039
Noncurrent regulatory assets		4,386			4,790		5,226		5,546		5,774
Other deferred debits and other assets		366			241		232		88		112
Total assets	$	10,018		$	10,087	$	10,373	$	10,691	$	10,710
Current liabilities	$	936		$	748	$	676	$	1,509	$	1,307
Long-term debt, including long-term debt to financing trusts(a)		4,143			4,628		5,239		4,951		5,438
Deferred credits and other liabilities		3,235			3,313		3,442		3,342		3,358
Mandatorily redeemable preferred securities of subsidiary trusts(a)		—			—		—		128		128
Mandatorily redeemable preferred stock		—			—		—		—		19
Shareholders’ equity		1,704			1,398		1,016		761		460
Total liabilities and shareholders’ equity	$	10,018		$	10,087	$	10,373	$	10,691	$	10,710

(a) Due to the adoptions of FIN 46 and FIN 46-R in 2003, the mandatorily redeemable preferred securities were reclassified as long-term debt to financing trusts in 2003.

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Generation

The selected 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 Operation included in ITEM 7 of this Report on Form 10-K.

The results of operations for Exelon Energy Company are not included in periods prior to 2004.

	For the Years Ended December 31,
(in millions)	2005			2004			2003			2002		2001
Statement of Income data:
Operating revenues	$	9,046		$	7,703		$	8,135		$	6,858	$	6,826
Operating income (loss)		1,852			1,039			(115	)		509		872
Income (loss) from continuing operations	$	1,109		$	657		$	(241	)	$	387	$	512
Income (loss) from discontinued operations		19			(16	)		—			—		—
Income (loss) before cumulative effect of changes in accounting principles		1,128			641			(241	)		387		512
Cumulative effect of changes in accounting principles (net of income taxes)		(30	)		32			108			13		12
Net income (loss)(a)	$	1,098		$	673		$	(133	)	$	400	$	524
(a)    Change between 2004 and 2003 is primarily due to the impairment of Boston Generating, LLC long-lived assets of $945 million in 2003.
	December 31,
(in millions)	2005			2004			2003			2002		2001
Balance Sheet data:
Current assets	$	3,040		$	2,321		$	2,438		$	1,805	$	1,435
Property, plant and equipment, net		7,464			7,536			7,106			4,698		2,003
Deferred debits and other assets		7,220			6,581			5,105			4,402		4,700
Total assets	$	17,724		$	16,438		$	14,649		$	10,905	$	8,138
Current liabilities	$	3,400		$	2,416		$	3,553		$	2,594	$	1,097
Long-term debt		1,788			2,583			1,649			2,132		1,021
Deferred credits and other liabilities		8,554			8,356			6,488			3,226		3,212
Minority interest		2			44			3			54		—
Member’s equity		3,980			3,039			2,956			2,899		2,808
Total liabilities and member’s equity	$	17,724		$	16,438		$	14,649		$	10,905	$	8,138

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

Exelon

General

Exelon is a public utility holding company. It operates through subsidiaries in the following business segments:

• ComEd, whose business includes the purchase and regulated retail and wholesale sale of electricity and distribution and transmission services in northern Illinois, including the City of Chicago.

• PECO, whose businesses include the purchase and regulated retail sale of electricity and distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and distribution services in the Pennsylvania counties surrounding the City of Philadelphia.

• Generation, which consists principally of the electric generating facilities and wholesale energy marketing operations of Generation, the competitive retail sales business of Exelon Energy Company and certain other generation projects.

See Note 22 of Exelon’s Notes to Consolidated Financial Statements for further segment information.

Through 2004, Exelon identified three operating segments—Energy Delivery (ComEd and PECO), Generation and Enterprises. Exelon sold or wound down substantially all components of Enterprises in 2004 and 2003. As such, Exelon ceased reporting Enterprises as a segment as of January 1, 2005. Additionally, as of the fourth quarter of 2005, Exelon reconsidered its previous presentation of segments and concluded that it would have been more appropriate to treat ComEd and PECO as separate operating segments for prior periods—as opposed to the single Energy Delivery operating segment. If ComEd and PECO would have previously been identified as separate operating segments, Exelon concluded that ComEd and PECO, nonetheless, would have been aggregated due to their similar economic characteristics, as a single reportable segment for segment reporting purposes. This aggregation would have resulted in substantially the same presentation in previously filed reports.

As a result of developments during the fourth quarter of 2005, Exelon has concluded that it can no longer aggregate ComEd and PECO as a single reportable segment. These developments include the approaching end of the regulatory transition period and rate freeze in Illinois, the opposition to rate increases expressed by the Attorney General of the State of Illinois, changes in the ComEd Board of Directors and the selection of executive officers of ComEd with no responsibilities outside of ComEd. For more information regarding ComEd’s regulatory issues, see ComEd—Retail Electric Services below and Note 4 of Exelon’s Notes to the Consolidated Financial Statements. As a result, ComEd and PECO are no longer reported as a combined Energy Delivery reportable segment. As such, Exelon now presents three reportable segments: ComEd, PECO and Generation. Prior period presentation has been adjusted for comparative purposes.

Exelon’s corporate operations, through its business services subsidiary, BSC, provide Exelon’s business segments with a variety of support services, including legal, human resources, financial, information technology, supply management and corporate governance services. ComEd and PECO also receive additional services from BSC, including planning and engineering of delivery systems, management of construction, operation and maintenance of the transmission and delivery systems, and management of other support services. Generation receives additional services from BSC for inventory and information technology support and management of other support services. These costs are allocated to the applicable business segments. Additionally, the results of Exelon’s corporate operations include costs for corporate governance and interest costs and income from various investment and financing activities.

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Exelon Corporation

Executive Overview

Financial Results.Exelon’s net income was $923 million in 2005 as compared to $1,864 million in 2004 and diluted earnings per average common share were $1.36 for 2005 as compared to $2.78 for 2004. The decrease was primarily due to the following:

• a $1.2 billion impairment charge associated with ComEd’s goodwill;

• losses for the cumulative effect of adopting FASB Interpretation No. (FIN) 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47);

• an increase to the reserve for estimated future asbestos-related bodily injury claims;

• increased depreciation and amortization expense, including CTC amortization at PECO;

• the gain associated with the sale of Boston Generating recorded in 2004;

• a gain recorded in 2004 as a cumulative effect of a change in accounting principle due to the adoption of FIN 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN 46-R); and

• a gain recorded in 2004 from the reimbursement of costs incurred prior to 2004 under a settlement with DOE related to spent nuclear fuel storage.

The factors driving the overall decrease in net income above were partially offset by the following:

• higher margins on Generation’s wholesale market sales;

• favorable weather conditions in Exelon’s service territories;

• reduced severance and severance-related charges;

• lower pension expense as a result of a discretionary pension contribution made in the first quarter of 2005; and

• losses associated with 2004 debt retirements at ComEd.

Investment Strategy. In 2005, Exelon continued to follow a disciplined approach in investing to maximize earnings and cash flows from its assets and businesses, while selling those investments that do not meet its strategic goals. Highlights from 2005 include the following:

• Proposed Merger with PSEG—On December 20, 2004, Exelon entered into a Merger Agreement with PSEG, and shareholders of both companies approved the transaction in July 2005. The Merger also received approval from regulatory agencies in New York, Texas and Connecticut, in addition to the FERC approval in June 2005. On September 13, 2005, Exelon announced that PECO had reached a partial settlement, subject to approval, with some but not all of the parties related to the Pennsylvania review of the Merger. The PAPUC approved the settlement and the Merger on January 27, 2006.

In New Jersey, hearings for the Merger review have been extended; they are expected to conclude on March 27, 2006. Settlement discussions began in December 2005 and are expected to resume after the hearings conclude. Scheduled dates for the Administrative Law Judge’s (ALJ) initial decision and final order from the NJBPU also may be extended, but no firm dates have been set.

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Other remaining regulatory reviews include the U.S. Department of Justice (DOJ). Exelon will attempt to reach a settlement that satisfactorily resolves issues and allows the Merger to close in the second quarter of 2006. However, in the absence of an earlier settlement, Exelon expects that the closing of the Merger will occur in the third quarter of 2006. See Note 3 of Exelon’s Notes to Consolidated Financial Statements for further information.

• Sithe—On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. Specifically, subsidiaries of Generation closed on the acquisition of Reservoir Capital Group’s 50% interest in Sithe and the sale of 100% of Sithe to Dynegy. See Note 3 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the sale of Generation’s investment in Sithe.

Financing Activities. During 2005, Exelon met its capital resource requirements primarily with internally generated cash. When necessary, Exelon obtains funds from external sources, including capital markets, and through bank borrowings. On March 7, 2005, Exelon entered into a $2 billion term loan agreement to fund pension contributions in the first quarter of 2005. On April 1, 2005, Exelon entered into a $500 million term loan agreement that was subsequently fully borrowed to reduce the $2 billion term loan referenced above. On June 9, 2005, Exelon issued and sold $1.7 billion of senior debt securities pursuant to its senior debt indenture, dated as of May 1, 2001, consisting of $400 million of 4.45% senior notes due 2010, $800 million of 4.90% senior notes due 2015 and $500 million of 5.625% senior notes due 2035. The net proceeds from the sale of the notes were used to repay the $1.5 billion in remaining principal due on the $2 billion term loan agreement and $200 million of the $500 million term loan agreement. See Notes 10 and 11 of Exelon’s Notes to Consolidated Financial Statements for further discussion.

Regulatory Developments—Illinois. As discussed in ITEM 1. Business and Note 4 of Exelon’s Notes to Consolidated Financial Statements, on January 24, 2006, the ICC, by a unanimous vote, approved a reverse-auction competitive bidding process for procurement of power by ComEd for the time period after 2006. To mitigate the impact on its residential customers of transitioning to this process, ComEd has offered to develop a “cap and deferral” proposal to ease the impact of the expected increase in rates on residential customers, some or all of which could require regulatory or legislative approval to implement. Several parties have indicated that they will petition the ICC for rehearing and will challenge the ICC decision in court. ComEd has also petitioned for rehearing of the ICC decision on certain issues, but that petition was denied by the ICC on February 8, 2006. It is also possible that interested parties could introduce legislation in Illinois in attempt to modify the procurement process or the rates that ComEd may charge consumers for the power ComEd purchases to meet the needs of consumers. The Illinois General Assembly has held hearings concerning generation procurement after 2006, and it may take action on this issue.

ComEd also has filed and has pending a regulatory proceeding before the ICC, referred to as the Rate Case. The Rate Case seeks, among other things, to allocate the costs of delivering electricity and to adjust ComEd’s rates for delivering electricity effective January 2, 2007. The Rate Case also proposes procedures under which ComEd will allocate the costs from the Procurement Case among ComEd customers. Several intervenors in the Rate Case, including the ICC staff and the Illinois Attorney General, have suggested, and provided testimony, that ComEd’s rates should actually be reduced. The results of the Rate Case are not expected to be known until the third quarter of 2006.

Market-Based Rates Filing.On July 5, 2005, the FERC approved Generation’s continued authority to charge market-based rates for wholesale sales of electricity, including to its affiliates ComEd and PECO. In the same order, the FERC stated that Generation had failed to address the affiliate abuse issue of the FERC’s market-based rate eligibility test. On August 4, 2005, Generation filed a Petition for Rehearing asking the FERC to rescind that part of its market-based rate order. Generation expects the FERC to make a decision in 2006. If the FERC were to suspend Generation’s market-based rate

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authority, Generation would be required to supply and implement a plan for mitigation of market power.FERC’s default mitigation would require Generation 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.

Repeal of PUHCA. Pursuant to the Energy Policy Act, PUHCA was repealed effective February 8, 2006. Under the Energy Policy Act, FERC obtained additional jurisdiction for merger review and for the review of affiliate transactions, and FERC’s financing jurisdiction resumed to the extent that it was preempted by PUHCA. Exelon continues to review the effects of the Energy Policy Act and FERC’s proposed rules with respect to future financing authority for its subsidiaries. To the extent that the SEC’s jurisdiction under PUHCA preempted certain aspects of state regulation, the repeal of PUHCA permits the states in which Exelon and its subsidiaries operate to adopt additional regulations if they so choose, absent any preemption by the FERC.

See ITEM 1. Business and Note 4 of Exelon’s Notes to the Consolidated Financial Statements for information on other regulatory matters.

Outlook for 2006 and Beyond.Exelon’s future financial results will be affected by a number of factors, including the following:

• Exelon expects the Merger will result in synergies, cost savings and operating efficiencies. Although Exelon expects to achieve these anticipated benefits of the Merger, achieving them, including synergies, is subject to a number of uncertainties. See ITEM 1A. Risk Factors.

• Certain governmental officials and consumer advocacy groups claim that ComEd’s retail rates for electricity should not be based solely on its cost to procure electricity and capacity in the wholesale market. Additionally, certain parties to ComEd’s Rate Case proceeding have indicated ComEd’s rates for delivering energy should be reduced and not increased. If the price at which ComEd is allowed to sell electricity beginning in 2007 is below ComEd’s cost to procure and deliver electricity, or if ComEd is unable to recover its costs and investment through the Rate Case, there may be material adverse consequences to ComEd and, possibly, Exelon. However, the ICC’s unanimous approval of the reverse-auction process, barring any successful appeals or change in law, should provide ComEd with stability and greater certainty that it will be able to procure energy and pass through the costs of that energy to ComEd’s customers beginning in 2007 through a transparent market mechanism in the reverse-auction process. The results of the Rate Case should be known during the third quarter of 2006.

• As of December 31, 2005, Hurricanes Katrina and Rita have not significantly impacted the Registrants’ results of operations and cash flows. However, Hurricanes Katrina and Rita are expected to impact the already increasing costs of certain supplies and the lead time to order these supplies in 2006. As a result, costs of such supplies could be $30 million to $40 million higher in 2006 compared to 2005, impacting the Registrants’ results of operations and cash flows.

• Exelon, through three wholly owned subsidiaries, has investments in synthetic fuel-producing facilities. Section 45k (formerly Section 29) of the Internal Revenue Code provides tax credits for the sale of synthetic fuel produced from coal. However, Section 45k contains a provision under which credits are phased out (i.e., eliminated) in the event crude oil prices for a year exceed certain thresholds.

The estimated annual average price per barrel of oil on the New York Mercantile Exchange, Inc. index (NYMEX) would have to exceed $59 and $61 in 2006 and 2007, respectively, for a

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phase-out to begin. In 2005, the estimated annual average price per barrel of $57 did not exceed the bottom of the phase-out range of $58. As a result, Exelon’s interests in synthetic fuel-producing facilities increased Exelon’s net income by $81 million during 2005. Based on the 2006 and 2007 NYMEX futures prices at December 31, 2005, Exelon estimates there will be a phase out of tax credits of 38% and 36% in 2006 and 2007, respectively. This would decrease Exelon’s net income as compared to 2005 by as much as $38 million and $36 million in 2006 and 2007, respectively. These estimates can change significantly due to the volatility in oil prices. See Liquidity and Capital Resources for further discussion.

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 within 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 areas described below require significant judgment in the application of accounting policy or in making estimates and assumptions in matters that are inherently uncertain and that may change in subsequent periods. Further discussion of the application of these accounting policies can be found in the Registrants’ Notes to Consolidated Financial Statements.

Asset Retirement Obligations (ARO) (Exelon, ComEd, PECO and Generation)

Nuclear Decommissioning (Exelon and Generation)

Generation must make significant estimates and assumptions in accounting for its obligation to decommission its nuclear generating plants in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143).

SFAS No. 143 requires that Generation estimate the fair value of its obligation for the future decommissioning of its nuclear generating plants. To estimate that fair value, Generation uses a probability-weighted, discounted cash flow model which considers multiple outcome scenarios based upon significant estimates and assumptions embedded in the following:

Decommissioning Cost Studies.Generation uses decommissioning cost studies prepared by a third party to provide a marketplace assessment of the costs and timing of decommissioning activities which are validated by comparison to current decommissioning projects and other third-party estimates. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclear units at a minimum of every five years.

Cost Escalation Studies.Generation uses cost escalation factors to escalate the estimated base year decommissioning costs, which are included in the decommissioning cost studies discussed above, through the decommissioning period for each of the units. Cost escalation studies are used to determine escalation factors and are based on inflation indices for labor, equipment and materials, energy and low-level radioactive waste disposal costs. Cost escalation studies are updated on an annual basis.

Probabilistic Cash Flow Models.Generation’s probabilistic cash flow models include the assignment of probabilities to various cost levels and various decommissioning timing scenarios. Probabilities assigned to cost levels include an assessment of the likelihood of actual costs plus 15% or minus 10% over the base cost scenario. The probabilities assigned to various timing scenarios incorporate the likelihood of continued operation through current license lives or through anticipated license renewals and the timing of DOE acceptance of spent nuclear fuel for permanent disposal.

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Discount Rates.The probability-weighted estimated future cash flows using these various scenarios are discounted using credit-adjusted, risk-free rates applicable to the various businesses in which each of the nuclear units originally operated.

Changes in the assumptions underlying the foregoing items could materially affect the decommissioning obligation recorded with a corresponding change to the asset retirement cost (ARC) asset. However, if the ARO relates to retired units, which have no remaining useful life and, likewise, no existing ARC, the offset may be recorded in current period earnings. Changes in the assumptions could affect future updates to the decommissioning obligation. For example, the 20-year average cost escalation rates used in the latest ARO calculation were approximately 3% to 4%. A uniform increase in these escalation rates of 25 basis points would increase the total ARO recorded by Exelon by approximately 9% or more than $350 million. Under SFAS No. 143, the nuclear decommissioning obligation is adjusted on an ongoing basis due to the passage of time and revisions to either the timing or amount of the original estimate of the future undiscounted cash flows required to decommission the nuclear plants. For more information regarding the adoption and ongoing application of SFAS No. 143, see Notes 1 and 13 of Exelon’s Notes to Consolidated Financial Statements.

Conditional ARO (Exelon, ComEd, PECO and Generation)

As of December 31, 2005, Exelon, ComEd, PECO and Generation adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). FIN 47 clarified that a legal obligation associated with the retirement of a long-lived asset whose timing and/or method of settlement are conditional on a future event is within the scope of SFAS No. 143. Under FIN 47, Exelon, ComEd, PECO and Generation are required to record a conditional ARO at its estimated fair value if that fair value can be reasonably estimated. As of December 31, 2005, Exelon, ComEd, PECO and Generation had liabilities of $236 million, $151 million, $20 million and $65 million, respectively, associated with their conditional AROs.

The adoption of FIN 47 required the Registrants to update an existing inventory, originally created for the adoption of SFAS No. 143, and to determine which, if any, of the conditional AROs could be reasonably estimated. The ability to reasonably estimate a conditional ARO was a matter of management judgment, based upon management’s ability to estimate a settlement date or range of settlement dates, a method or potential method of settlement and probabilities associated with the potential dates and methods of settlement of its conditional AROs. In determining whether their conditional AROs could be reasonably estimated, management considered the Registrants’ past practices, industry practices, management’s intent and the estimated economic lives of the assets. The fair value of the conditional AROs was then estimated using an expected present value technique. Additionally, Exelon, ComEd and PECO assessed the likelihood of recovering these obligations from customers which led to the recognition of regulatory assets. Changes in management’s assumptions regarding settlement dates, settlement methods, assigned probabilities or recovery mechanisms could have a material effect on the liabilities recorded by each Registrant at December 31, 2005 as well as the associated cumulative effect of a change in accounting principle recorded at Exelon, ComEd, PECO and Generation and the associated regulatory assets recorded at Exelon, ComEd and PECO. The liabilities associated with conditional AROs will be adjusted on an ongoing basis due to the passage of time, new laws and regulations and revisions to either the timing or amount of the original estimates of undiscounted cash flows. These adjustments could have a significant impact on the Consolidated Balance Sheets and Consolidated Statements of Income of the Registrants. For more information regarding the adoption and ongoing application of FIN 47, see Notes 1 and 14 of Exelon’s Notes to Consolidated Financial Statements.

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Asset Impairments (Exelon, ComEd, PECO and Generation)

Goodwill (Exelon and ComEd)

As of December 31, 2004, Exelon and ComEd had approximately $4.7 billion of goodwill, which related entirely to the goodwill recorded upon the acquisition of ComEd. Exelon and ComEd perform assessments for impairment of their goodwill at least annually, or more frequently if events or circumstances indicate that goodwill might be impaired. Application of the goodwill impairment test requires management’s judgments, 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.

Exelon and ComEd performed their annual assessments of goodwill impairment as of November 1, 2005 and determined that goodwill was impaired by $1.2 billion. Exelon assesses goodwill impairment at its ComEd reporting unit; accordingly, a goodwill impairment charge at ComEd is fully reflected in Exelon’s results of operations. After reflecting the impairment, Exelon and ComEd have $3.5 billion of goodwill as of December 31, 2005.

In the assessments, Exelon and ComEd estimated the fair value of the ComEd reporting unit using a probability-weighted, discounted cash flow model with multiple scenarios. The fair value incorporates management’s assessment of current events and expected future cash flows. The 2005 impairment was driven by changes in the fair value of ComEd’s purchase power agreement with Generation, the upcoming end of ComEd’s transition period and related transition revenues, regulatory uncertainty in Illinois as of November 1, 2005, anticipated increases in capital expenditures in future years and decreases in market valuations of comparable companies that are utilized to estimate the fair value of ComEd. Changes in assumptions regarding these variables or in the assessment of how they interrelate could produce a different impairment result, which could be material. For example, a hypothetical decrease of approximately 10% in ComEd’s expected discounted cash flows would result in additional impairment for both ComEd and Exelon of $1.2 billion. An additional impairment would require Exelon and ComEd to further reduce both goodwill and current period earnings by the amount of the impairment.

Long-Lived Assets (Exelon, ComEd, PECO and Generation)

Exelon, ComEd, PECO and Generation evaluate the carrying value of their long-lived assets, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. The review of long-lived assets for impairment requires significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. For the generation business, forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power and costs of fuel. A variation in the assumptions used could lead to a different conclusion regarding the realizability of an asset and, thus, could have a significant effect on the consolidated financial statements. An impairment would require the affected registrant to reduce both the long-lived asset and current period earnings by the amount of the impairment.

Investments (Exelon, ComEd, PECO and Generation)

Exelon, ComEd, PECO and Generation had approximately $6,398 million, $75 million, $95 million and $5,705 million, respectively, of investments, including investments held in nuclear decommissioning trust funds, recorded as of December 31, 2005. Exelon, ComEd, PECO and Generation consider investments to be impaired when a decline in fair value below cost is judged to be other-than-temporary. If the cost of an investment exceeds its fair value, they evaluate, among other factors, general market conditions, the duration and extent to which the fair value is less than cost, as

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well as their intent and ability to hold the investment. The Registrants may also consider specific adverse conditions related to the financial health of and business outlook for the investee when reviewing an investment for impairment. An impairment would require the affected registrant to reduce both the investment and current period earnings by the amount of the impairment.

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

The Registrants 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. Changes to depreciation estimates in future periods could have a significant impact on the amount of property, plant and equipment recorded and the depreciation charged to the financial statements.

Historically, Generation has extended the estimated service lives of certain nuclear-fuel generating facilities based upon Generation’s intent to apply for license renewals for these facilities. While Generation has received license renewals for certain facilities, and has applied for or expects to apply for and obtain approval of license renewals for the remaining facilities, circumstances may arise that would prevent Generation from obtaining additional license renewals. A change in depreciation estimates resulting from Generation’s inability to receive additional license renewals could have a significant effect on Generation’s results of operations.

In August 2005, PECO filed a depreciation rate study with the PAPUC. The impact of the new rates, based on the study, which will be effective March 2006, is not expected to be material.

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

Exelon sponsors defined benefit pension plans and postretirement welfare benefit plans applicable to essentially all ComEd, PECO, Generation and BSC employees and certain Enterprises employees. See Note 15 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the accounting for Exelon’s 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, Exelon utilizes assumptions about the future, including the expected rate of return on plan assets, the discount rate applied to benefit obligations, rate of compensation increases 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 pension cost was 9.00% in 2005, 2004 and 2003. The weighted average EROA assumption used in calculating other postretirement benefit costs was 8.30% in 2005 compared to a range of 8.33% to 8.35% in 2004 and 8.40% for 2003. 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 discount rate for determining the plan obligations was 5.60%, 5.75% and 6.25% at December 31, 2005, 2004 and 2003, respectively. The discount rates at December 31, 2004 and 2003 were selected by reference to the Moody’s Aa Corporate Bond Index adjusted to reflect the duration of expected future cash flows for pension and other postretirement welfare benefit payments. At

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December 31, 2005, the discount rate was determined by developing a spot rate curve based on the yield to maturity of more than 400 Aa graded non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and other postretirement welfare benefit obligations. The spot rates are used to discount the estimated distributions under the pension and other postretirement welfare benefit plans. The discount rate is the single level rate that produces the same result as the spot rate curve.

The following tables illustrate the effects of changing the major actuarial assumptions discussed above (dollars in millions):

Change in Actuarial Assumption	Impact on Projected Benefit Obligation at December 31, 2005		Impact on Pension Liability at December 31, 2005		Impact on 2006 Pension Cost
Pension benefits
Decrease discount rate by 0.5%		$683		$548		$50
Decrease rate of return on plan assets by 0.5%		—		—		45
Change in Actuarial Assumption	Impact on Other Postretirement Benefit Obligation at December 31, 2005		Impact on Postretirement Benefit Liability at December 31, 2005		Impact on 2006 Postretirement Benefit Cost
Postretirement benefits
Decrease discount rate by 0.5%	$	208	$	—	$	24
Decrease rate of return on plan assets by 0.5%		—		—		6

Assumed health care cost trend rates also have a significant effect on the costs reported for Exelon’s postretirement benefit plans. To estimate the 2005 cost, Exelon assumed a health care cost trend rate of 9%, decreasing to an ultimate trend rate of 5% in 2010, compared to the 2004 assumption of 10%, decreasing to an ultimate trend rate of 4.5% in 2011. A one-percentage point change in assumed health care cost trend rates in 2005 would have had the following effects (dollars in millions):

Effect of a one percentage point increase in assumed health care cost trend
on total service and interest cost components	$	41
on postretirement benefit obligation	$	399
Effect of a one percentage point decrease in assumed health care cost trend
on total service and interest cost components	$	(30	)
on postretirement benefit obligation	$	(297	)

The assumptions are reviewed at the beginning of each year during Exelon’s annual review process and at any interim remeasurement of the plan obligations. The impact of assumption changes is reflected in the recorded pension and postretirement benefit 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 and postretirement benefit amounts and funding requirements could also change.

In 2005, Exelon incurred approximately $221 million in costs associated with its pension and postretirement benefit plans. The decrease in Exelon’s pension and postretirement benefit costs in 2005 compared to 2004 and 2003 was primarily attributable to discretionary pension contributions of $2 billion made during the first quarter of 2005.

Regulatory Accounting (Exelon, ComEd and PECO)

Exelon, ComEd and PECO account for their regulated electric and gas operations in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), which

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requires Exelon, ComEd and PECO to reflect the effects of rate regulation in their financial statements. Use of SFAS No. 71 is applicable to 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, 2005, Exelon, ComEd and PECO have concluded that the operations of ComEd and PECO meet the criteria. If it is concluded in a future period that a separable portion of their businesses no longer meets the criteria, Exelon, ComEd and PECO are required to eliminate the financial statement effects of regulation for that part of their business, which would include the elimination of any or all regulatory assets and liabilities that had been recorded in their Consolidated Balance Sheets. The impact of not meeting the criteria of SFAS No. 71 could be material to the financial statements as a one-time extraordinary item and through impacts on continuing operations. See Note 4 of Exelon’s Notes to Consolidated Financial Statements 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, 2005, Exelon and PECO had recorded $4.4 billion of net regulatory assets within their Consolidated Balance Sheets. At December 31, 2005, Exelon and ComEd had recorded $2.2 billion of net regulatory liabilities within their Consolidated Balance Sheets. See Note 21 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the significant regulatory assets and liabilities of Exelon, ComEd and PECO.

For each regulatory jurisdiction where they conduct business, Exelon, ComEd and PECO 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 the current rates include the recovery and settlement of existing regulatory assets and liabilities, respectively, and rates in effect during the rate freeze or rate cap periods are expected to allow Exelon, ComEd and PECO 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 at the Federal level and in the states where ComEd and PECO 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 written-off and recognized in current period earnings. A write-off of regulatory assets could limit the ability of ComEd and PECO to pay dividends under Federal and state law.

Accounting for Derivative Instruments (Exelon, ComEd, PECO and Generation)

The Registrants enter into derivatives to manage their exposure to fluctuations in interest rates, changes in interest rates related to planned future debt issuances and changes in the fair value of outstanding debt. 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. All of the Registrant’s derivative activities are in accordance with Exelon’s Risk Management Policy (RMP).

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The Registrants account 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 or normal sales exception. Derivatives recorded at fair value on the balance sheet are presented as current or noncurrent mark-to-market derivative assets or liabilities. 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 earnings as an offset to the changes in fair value of the exposure being hedged or deferred in accumulated other comprehensive income and recognized in earnings when the hedged transaction occurs.

Normal Purchases and Normal Sales Exception.The availability of the normal purchases and normal sales exception is based upon the assessment of the ability and intent to deliver or take delivery of the underlying item. This assessment is based primarily on internal models that forecast customer demand for electricity and gas 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. If it was determined that a transaction designated as a “normal” purchases or a “normal” sale no longer met the scope exceptions, the fair value of the related contract would be recorded on the balance sheet and immediately recognized through earnings.

Energy Contracts.Identification of an energy contract as a qualifying cash-flow hedge requires Generation to determine that the contract is in accordance with the RMP, 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. Generation reassesses its cash-flow hedges on a regular basis to determine if they continue to be effective and that the forecasted future transactions are probable. When a contract does not meet the effective or probable criteria of SFAS No. 133, hedge accounting is discontinued and changes in the fair value of the derivative are recorded through earnings.

As a part of accounting for derivatives, the Registrants 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 expected changes in the fair value in deciding whether or not to enter into derivative transactions, and in determining the initial accounting treatment for derivative transactions. Generation uses 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, Generation uses internal models to determine the fair value. These internal models include assumptions of the future prices of energy based on the specific market in which the energy is being purchased, using externally available forward market pricing curves for all periods possible under the pricing model. Generation uses the Black model, a standard industry valuation model, to determine the fair value of energy derivative contracts that are marked-to-market.

Interest-Rate Derivative Instruments.To determine the fair value of interest-rate swap agreements, the Registrants use external dealer prices or internal valuation models that utilize assumptions of available market pricing curves.

Accounting for Contingencies (Exelon, ComEd, PECO and Generation)

In the preparation of their financial statements, the Registrants make judgments regarding the future outcome of contingent events and record loss contingency amounts that are probable and reasonably estimated based upon available information. The amounts recorded may differ from the actual income or expense that occurs when the uncertainty is resolved. The estimates that the

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Registrants make in accounting for contingencies and the gains and losses that they record upon the ultimate resolution of these uncertainties have a significant effect on the liabilities and expenses in their financial statements.

Taxation

The Registrants are required to make judgments regarding the potential tax effects of various financial transactions and results of operations in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate, sales and 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 have been taken. The Registrants also estimate their ability to utilize tax attributes, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Other than as noted below, the Registrants do not record valuation allowances for deferred tax assets related to capital losses that the Registrants believe will be realized in future periods. While the Registrants believe the resulting tax reserve balances as of December 31, 2005 reflect the probable expected outcome of pending 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 favorable or unfavorable adjustments to their consolidated financial statements and such adjustments could be material.

Environmental Costs

As of December 31, 2005, Exelon, ComEd, PECO and Generation had accrued liabilities of $128 million, $54 million, $47 million and $27 million, respectively, for environmental investigation and remediation costs. These liabilities are based upon estimates with respect to the number of sites for which the Registrants 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 $89 million, $48 million, and $41 million of the total accrued for Exelon, ComEd, and PECO, respectively. Generation has no accrued environmental investigation and remediation costs recorded on a discounted basis. Where timing and amounts cannot be reliably estimated, amounts are recognized on an undiscounted basis. Such amounts represent $39 million, $6 million, $6 million and $27 million, respectively, of the total accrued liabilities for Exelon, ComEd, PECO and Generation. Estimates can be affected by the factors noted above as well as by changes in technology, regulations or the requirements of local governmental authorities.

Asbestos Personal Injury Claims

As of December 31, 2005, Exelon and Generation have approximately $50 million reserved in total for asbestos-related bodily injury claims. Approximately $9 million of this amount relates to 120 open claims presented to Generation as of December 31, 2005, while the remaining $41 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2030 based on actuarial assumptions and analysis. Exelon’s and Generation’s management each determined that it was not reasonable to estimate future asbestos-related personal injury claims beyond 2030 based on the historical claims data available and the significant amount of judgment required to estimate this liability. In calculating the future losses, management and the actuaries made various assumptions, including but not limited to, the overall number of future claims estimated through the use of actuarial models, Exelon’s estimated portion of future settlements and obligations, the distribution of exposure sites, the anticipated future mix of diseases that related to asbestos exposure and the anticipated levels of awards made to plaintiffs. Exelon plans to obtain annual updates of the estimate of future losses. The amounts recorded by Generation for estimated future asbestos-related bodily injury claims are based upon historical experience and third-party actuarial studies. Projecting

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future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding asbestos-related litigation and possible legislative measures in the United States, could cause the actual costs to be higher or lower than projected. Management cautions, however, that these estimates for asbestos-related bodily injury cases and settlements are difficult to predict and may be influenced by many factors. Accordingly, these matters, if resolved in a manner different from the estimate, could have a material effect on Exelon’s or Generation’s results of operations, financial position and cash flow.

Severance Accounting (Exelon, ComEd, PECO and Generation)

The Registrants provide severance benefits to terminated employees pursuant to pre-existing severance plans primarily based upon each individual employee’s years of service with the Registrants and compensation level. The Registrants accrue severance benefits that are considered probable and can 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 estimating severance charges is the determination of the number of positions to be eliminated. The Registrants base their estimates on their current plans and ability to determine the appropriate staffing levels to effectively operate their businesses. Exelon, ComEd, PECO and Generation recorded severance charges (benefits) of $(14) million, $(9) million, $1 million and $(4) million, respectively, in 2005, and severance charges of $32 million, $10 million, $3 million and $2 million, respectively, in 2004, related to personnel reductions. The Registrants may incur further severance costs if they identify additional positions to be eliminated. These costs will be recorded in the period in which the costs can be reasonably estimated.

Revenue Recognition (Exelon, ComEd, PECO and Generation)

Revenues related to the sale of energy are recorded when service is rendered or energy is delivered to customers. The determination of ComEd’s, PECO’s and Exelon Energy’s 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 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 usage 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 of ComEd, PECO and Generation included estimates of $287 million, $175 million and $89 million, respectively, for unbilled revenue as of December 31, 2005 as a result of unread meters at ComEd, PECO and Exelon Energy. Increases in volumes delivered to the utilities’ customers and favorable rate mix due to changes in usage patterns in customer classes in the period could be significant to the calculation of 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 operating revenues would remain materially unchanged.

The determination of Generation’s energy sales, excluding Exelon Energy’s, 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 are estimated and the corresponding unbilled revenue is recorded. Customer accounts receivable of Exelon and Generation as of December 31, 2005 include unbilled energy revenues of $435 million related to unbilled energy sales of Generation. Increases in volumes delivered to the wholesale customers in the period, as well as price, would increase unbilled revenue.

Generation’s revenue from service agreements, such as the nuclear Operating Service Agreement with PSEG Nuclear, is dependent upon when the services are rendered. Service agreements representing a cost recovery arrangement are presented gross within revenues for the amounts due from the party receiving the service, and the costs associated with providing the service are presented within operating and maintenance expenses.

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Results of Operations(Dollars in millions except for per share data, unless otherwise noted)

Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

Significant Operating Trends—Exelon

Exelon Corporation	2005			2004			Favorable (unfavorable) variance
Operating revenues	$	15,357		$	14,133		$	1,224
Purchased power and fuel expense		5,646			4,929			(717	)
Operating and maintenance expense		3,718			3,700			(18	)
Impairment of goodwill		1,207			—			(1,207	)
Depreciation and amortization		1,334			1,295			(39	)
Operating income		2,724			3,499			(775	)
Other income and deductions		(829	)		(922	)		93
Income from continuing operations before income taxes and minority interest		1,895			2,577			(682	)
Income taxes		944			713			(231	)
Income from continuing operations		951			1,870			(919	)
Income (loss) from discontinued operations, net of income taxes		14			(29	)		43
Income before cumulative effect of a change in accounting principle		965			1,841			(876	)
Cumulative effect of changes in accounting principles		(42	)		23			(65	)
Net income		923			1,864			(941	)
Diluted earnings per share	$	1.36		$	2.78		$	(1.42	)

Net Income.Net income for 2005 reflects an impairment charge of $1,207 million associated with ComEd’s goodwill and losses of $42 million for the cumulative effect of adopting FIN 47, partially offset by higher realized prices on market sales at Generation and favorable weather conditions in the ComEd and PECO service territories. Net income for 2004 reflects income of $32 million for the adoption of FIN 46-R, partially offset by a loss of $9 million related to the adoption of Emerging Issues Task Force (EITF) Issue No. 03-16, “Accounting for Investments in Limited Liability Companies” (EITF 03-16). See Note 1 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the adoption of FIN 46-R.

Operating Revenues.Operating revenues increased primarily due to increased revenues at ComEd and PECO and increased revenues from non-affiliates at Generation. The increase in revenues at ComEd and PECO was primarily due to favorable weather conditions, an increase in the number of customers choosing ComEd or PECO as their electric supplier and higher transmission revenues, partially offset by decreased CTC collections at ComEd. The increase in revenues from non-affiliates at Generation was primarily due to higher prices on energy sold in the market, partially offset by an increase in the percentage of energy produced and sold to ComEd and PECO and the sale of Boston Generating in 2004. See further analysis and discussion of operating revenues by segment below.

Purchased Power and Fuel Expense.Purchased power and fuel expense increased primarily due to overall higher market energy prices and higher natural gas and oil prices, partially offset by the decrease in fuel expense due to the sale of Boston Generating in 2004, favorable mark-to-market adjustments related to non-trading activities and the expiration of the purchase power agreement with Midwest Generation in 2004. Purchased power represented 22% of Generation’s total supply in 2005 compared to 24% in 2004. See further analysis and discussion of purchased power and fuel expense by segment below.

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Operating and Maintenance Expense.Operating and maintenance expense increased primarily due to a gain recorded in 2004 related to the DOE Settlement, an increase to the reserve for the estimated future asbestos-related bodily injury claims that was recorded in 2005, higher costs associated with planned nuclear refueling outages, and increased costs related to an operating agreement with a subsidiary of Tamuin International, Inc. (formerly Sithe International, Inc.), partially offset by the sale of Boston Generating in 2004 and decreased severance and benefit expense. See further discussion of operating and maintenance expenses by segment below.

Impairment of Goodwill. ComEd recorded a $1,207 million charge during 2005 to impair its goodwill.

Depreciation and Amortization Expense. The increase in depreciation and amortization expense was primarily due to additional plant placed in service, additional amortization of the CTC at PECO and accelerated amortization of PECO’s current customer information and billing system, partially offset by the establishment of an ARC asset for retired nuclear units in 2004 which was immediately impaired through depreciation expense.

Operating Income.Exclusive of the changes in operating revenues, purchased power and fuel expense, operating and maintenance expense, impairment of goodwill and depreciation and amortization expense discussed above, the change in operating income was the result of increased taxes other than income, partially offset by the sale of Boston Generating in 2004 and reduced property tax expense.

Other Income and Deductions. The change in other income and deductions reflects a 2004 charge at ComEd associated with the accelerated retirement of debt and the related reduction in interest expense from these debt retirements and increased realized gains related to the decommissioning trust fund investments for the AmerGen plants, partially offset by increased interest expense on short-term debt at Exelon, increased losses from Exelon’s investment in synthetic fuel-producing facilities and an $85 million gain recorded in 2004 on the sale of Boston Generating.

Effective Income Tax Rate.The effective income tax rate from continuing operations was 50% for 2005 compared to 28% for 2004. Exclusive of the goodwill impairment charge, the effective income tax rate for 2005 was 30%. See Note 12 of Exelon’s Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

Discontinued Operations. On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. In addition, Exelon has sold or wound down substantially all components of Enterprises and AllEnergy, a business within Exelon Energy. Accordingly, the results of operations and any gain or loss on the sale of these entities have been presented as discontinued operations within Exelon’s and Generation’s Consolidated Statements of Income. See Notes 2 and 3 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the presentation of Sithe, certain Enterprises businesses and AllEnergy as discontinued operations and the sale of Sithe. The results of Sithe and AllEnergy are included in the Generation discussion below.

The income from discontinued operations increased by $43 million from 2004 to 2005 primarily due to the gain on the sale of Sithe in the first quarter of 2005.

Cumulative Effect of Changes in Accounting Principles. The cumulative effect of changes in accounting principles reflects the impact of adopting FIN 47 as of December 31, 2005 and the consolidation of Sithe in accordance with FIN 46-R as of March 31, 2004. See Notes 1 and 14 of Exelon’s Notes to Consolidated Financial Statements for further discussion of the consolidation of Sithe and the adoption of FIN 47, respectively.

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Results of Operations by Business Segment

The comparisons of 2005 and 2004 operating results and other statistical information set forth below include intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

Net Income (Loss) from Continuing Operations by Business Segment

	2005			2004		Favorable (unfavorable) variance
ComEd	$	(676	)	$	676	$	(1,352	)
PECO		520			455		65
Generation		1,109			657		452
Other(a)		(2	)		82		(84	)
Total	$	951		$	1,870	$	(919	)

(a) Other includes corporate operations, shared service entities, including BSC, Enterprises, investments in synthetic fuel-producing facilities and intersegment eliminations.

Income (Loss) Before Cumulative Effect of Changes in Accounting Principles by Business Segment

	2005			2004		Favorable (unfavorable) variance
ComEd	$	(676	)	$	676	$	(1,352	)
PECO		520			455		65
Generation		1,128			641		487
Corporate(a)		(7	)		69		(76	)
Total	$	965		$	1,841	$	(876	)

(a) Other includes corporate operations, shared service entities, including BSC, Enterprises, investments in synthetic fuel-producing facilities and intersegment eliminations.

Net Income (Loss) by Business Segment

	2005			2004		Favorable (unfavorable) variance
ComEd	$	(685	)	$	676	$	(1,361	)
PECO		517			455		62
Generation		1,098			673		425
Corporate		(7	)		60		(67	)
Total	$	923		$	1,864	$	(941	)

(a) Other includes corporate operations, shared service entities, including BSC, Enterprises, investments in synthetic fuel-producing facilities and intersegment eliminations.

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Results of Operations–ComEd

	2005			2004			Favorable (unfavorable) variance
Operating revenues	$	6,264		$	5,803		$	461
Operating expenses
Purchased power		3,520			2,588			(932	)
Operating and maintenance		833			897			64
Impairment of goodwill		1,207			—			(1,207	)
Depreciation and amortization		413			410			(3	)
Taxes other than income		303			291			(12	)
Total operating expense		6,276			4,186			(2,090	)
Operating income (loss)		(12	)		1,617			(1,629	)
Other income and deductions
Interest expense		(295	)		(369	)		74
Equity in losses of unconsolidated affiliates		(14	)		(19	)		5
Net loss on extinguishment of long-term debt		—			(130	)		130
Other, net		8			34			(26	)
Total other income and deductions		(301	)		(484	)		183
Income (loss) before income taxes and cumulative effect of a change in accounting principle		(313	)		1,133			(1,446	)
Income taxes		363			457			94
Income (loss) before cumulative effect of a change in accounting principles		(676	)		676			(1,352	)
Cumulative effect of change in accounting principle		(9	)		—			(9	)
Net income (loss)	$	(685	)	$	676		$	(1,361	)

Net Loss. ComEd’s net loss in 2005 was driven by the impairment of goodwill and higher purchased power expense, partially offset by higher operating revenues due to favorable weather and due to the impacts of a 2004 charge associated with the accelerated retirement of long-term debt and lower interest expense.

Operating Revenues. The changes in operating revenues for 2005 compared to 2004 consisted of the following:

	Increase (decrease)
Weather	$	415
Customer choice		81
Rate changes and mix		(66	)
Volume		(3	)
Other		(9	)
Retail revenue		418
PJM transmission		58
T&O / SECA rates		(28	)
Other		13
Wholesale and miscellaneous revenues		43
Increase in operating revenues	$	461

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Weather.Revenues were higher by $415 million due to favorable weather conditions in 2005 compared to 2004. 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 in non-summer months reduces demand. In ComEd’s service territory, cooling and heating degree days were 90% and 1% higher, respectively, than the prior year.

Customer choice. For 2005 and 2004, 33% and 35% of energy delivered to ComEd’s retail customers was provided by alternative electric suppliers or under the Power Purchase Option (PPO).

All ComEd customers have the choice to purchase energy from an alternative electric supplier. This choice does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation service. As of December 31, 2005, one alternative supplier was approved to serve residential customers in the ComEd service territory. However, no residential customers have selected this alternative supplier.

	2005		2004
Retail customers purchasing energy from an alternative electric supplier:
Volume (GWhs)(a)	19,310		20,939
Percentage of total retail deliveries	21	%	24	%
Retail customers purchasing energy from an alternative electric supplier or the ComEd PPO:
Number of customers at period end	21,276		22,161
Percentage of total retail customers	(b	)	(b	)
Volume (GWhs)(a)	30,905		30,426
Percentage of total retail deliveries	33	%	35	%

(a) One GWh is the equivalent of one million kilowatthours (kWh).

(b) Less than one percent.

Rate changes and mix. The change is primarily due to the increased wholesale market price of electricity and other adjustments to the energy component of the CTC calculation which resulted in a decrease of $64 million to $105 million in 2005 as compared to 2004. As a result of increasing mitigation factors and changes in energy prices, ComEd anticipates that CTC revenues will range from $35 million to $50 million in 2006. Under current Illinois law, no CTCs will be collected after 2006.

PJM transmission.ComEd’s transmission revenues increased by $58 million in 2005 due to ComEd’s May 1, 2004 entry into PJM.

T&O / SECA rates. Revenues decreased $28 million as a result of the elimination of T&O rates in accordance with FERC orders that became effective December 1, 2004. Effective December 1, 2004, PJM became obligated to pay SECA collections to ComEd, and ComEd became obligated to pay SECA charges—see “Purchased Power Expense” below. See Note 3 of ComEd’s Notes to Consolidated Financial Statements for more information on T&O / SECA rates.

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Purchased Power Expense.The changes in purchased power expense for 2005 compared to 2004 consisted of the following:

	Increase (decrease)
Prices	$	606
Weather		200
Customer choice		65
PJM		63
Volume		7
T&O collections / SECA rates		(15	)
Other		6
Increase in purchased power expense	$	932

Prices.Purchased power increased due to higher prices associated with ComEd’s PPA with Generation of $497 million, and ancillary services of $109 million from PJM. In 2000, ComEd and Generation entered into a PPA that fixed the pricing for purchased power through December 31, 2004 based upon the then current market prices. As a result of the Amended and Restated Purchase Power Agreement as of April 30, 2004 with Generation, starting in January 1, 2005, ComEd began paying higher prices for its purchased power from Generation and ceased to procure its ancillary services from Generation. This agreement fixed the pricing for purchased power through December 31, 2006 based upon the current market prices as of April 30, 2004.

Weather.The $200 million increase in purchased power expense attributable to weather was due to favorable weather conditions in the ComEd service territory, which increased the amount of electricity sold.

Customer choice.The $65 million increase in purchased power expense from customer choice was primarily due to fewer ComEd non-residential customers electing to purchase energy from an alternative electric supplier.

PJM.The $63 million increase reflects higher transmission and purchased power expense of $57 million due to ComEd’s May 1, 2004 entry into PJM and PJM administrative fees that increased by $6 million over 2004 fees.

T&O Collections / SECA rates. Prior to FERC orders issued in November 2004, ComEd collected T&O rates for transmission service scheduled out of or across ComEd’s transmission system. Rates collected as the transmission owner were recorded in operating revenues. After joining PJM on May 1, 2004, PJM allocated T&O collections to ComEd as a load-serving entity. The collections received by ComEd as a load-serving entity were recorded as a decrease to purchased power expense. ComEd’s purchased power expense increased $14 million due to ComEd no longer collecting T&O revenues in 2005.

Effective December 1, 2004, PJM became obligated to pay SECA collections to ComEd and ComEd became obligated to pay SECA charges. During 2005, ComEd recorded SECA collections net of SECA charges of $29 million. See Note 3 of ComEd’s Notes to Consolidated Financial Statements for more information on T&O /SECA rates.

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Operating and Maintenance Expense.The changes in operating and maintenance expense for 2005 compared to 2004 consisted of the following:

	Increase (decrease)
Severance-related expenses(a)	$	(47	)
Employee fringe benefits(b)		(18	)
Pension expense and deferred compensation(c)		(15	)
Allowance for uncollectible accounts		(13	)
Injuries and damages		(2	)
Corporate allocations(b)		15
Storm costs		14
Contractors		12
PSEG merger integration costs		8
Other		(18	)
Decrease in operating and maintenance expense	$	(64	)

(a) Consists of salary continuance severance costs, curtailment charges for pension and other postretirement benefits, and special termination benefit charges related to other postretirement benefits. The decrease reflects reduced severance-related activity in 2005 as compared to 2004.

(b) Excludes severance-related expenses and pension expense. Reflects fewer employees compared to prior year and a reduction in 2005 related to estimated medical plan fees. A portion of the employee reduction is offset by an increase in corporate allocations.

(c) Pension expense in 2005 is lower than in 2004 due in large part to significant pension plan contributions made in the first quarter of 2005. See Note 13 of ComEd’s Notes to Consolidated Financial Statements for additional information.

Impairment of Goodwill. During the fourth quarter of 2005, ComEd completed the annually required assessment of goodwill for impairment purposes. The assessment compares the carrying value of goodwill to the estimated fair value of goodwill as of a point in time (November 1). The estimated fair value incorporates management’s assessment of current events and expected future cash flows. The 2005 test indicated that ComEd’s goodwill was impaired and a charge of $1.2 billion was recorded. The 2005 impairment was driven by changes in the fair value of ComEd’s purchase power agreement with Generation, the upcoming end of ComEd’s transition period and related transition revenues, regulatory uncertainty in Illinois as of November 1, 2005, anticipated increases in capital expenditures in future years and decreases in market valuations of comparable companies that are utilized to estimate the fair value of ComEd. After reflecting the impairment, ComEd has approximately $3.5 billion of remaining goodwill as of December 31, 2005.

Depreciation and Amortization Expense.The changes in depreciation and amortization expense for 2005 compared to 2004 consisted of the following:

	Increase (decrease)
Depreciation expense	$	17
Other amortization expense		(14	)
Increase in depreciation and amortization expense	$	3

The increase in depreciation expense is primarily due to capital additions.

The decrease in other amortization expense was primarily due to completing the amortization of one of ComEd’s software packages in 2004.

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Taxes Other Than Income.The changes in taxes other than income for 2005 compared to 2004 consisted of the following:

	Increase (decrease)
Taxes on utility revenues(a)	$	13
Tax refund(b)		6
Other		(7	)
Increase in taxes other than income	$	12

(a) As these taxes were collected from customers and remitted to the taxing authorities and included in revenues and expenses, the increase in expense was offset by a corresponding increase in revenues.

(b) During 2004, a refund was received for Illinois electricity distribution taxes.

Interest Expense.The reduction in interest expense of $74 million for 2005 compared to 2004 was primarily due to long-term debt retirements and prepayments in 2004 pursuant to Exelon’s accelerated liability management plan and scheduled payments on long-term debt owed to the ComEd Funding Trust.

Equity in Losses of Unconsolidated Affiliates.The decrease in equity in losses of unconsolidated affiliates was a result of a decrease in interest expense of the deconsolidated financing trusts due to scheduled repayments of outstanding long-term debt.

Net Loss on Extinguishment of Long-Term Debt. In 2004, Exelon initiated an accelerated liability management plan at ComEd that resulted in the retirement of approximately $768 million of long-term debt, of which $618 million was retired during the third quarter of 2004. During 2004, ComEd recorded a charge of $130 million associated with the retirement of debt under the plan. The components of this charge included the following: $86 million related to prepayment premiums; $12 million related to net unamortized premiums, discounts and debt issuance costs; $24 million of losses on reacquired debt previously deferred as regulatory assets; and $12 million related to settled cash-flow interest-rate swaps previously deferred as regulatory assets partially offset by $4 million of unamortized gain on settled fair value interest-rate swaps.

Other, Net.The changes in other, net for 2005 compared to 2004 consisted of the following:

	Increase (decrease)
Loss on settlement of cash-flow swaps(a)	$	(15	)
Interest income on long-term receivable from UII, LLC(b)		(16	)
Other		5
Decrease in other, net	$	(26	)

(a) See Note 14 of ComEd’s Notes to Consolidated Financial Statements for further information.

(b) The decrease in interest income on the long-term receivable from UII, LLC resulted from this receivable being repaid in late 2004.

Income Taxes. The effective income tax rate was (116.0)% and 40.3% for 2005 and 2004, respectively. Exclusive of the goodwill impairment charge, the effective rate for 2005 was 40.6%. See Note 10 of ComEd’s Notes to Consolidated Financial Statements for further details of the components of the effective income tax rates.

Cumulative Effect of a Change in Accounting Principle. The cumulative effect of a change in accounting principle reflects the impact of adopting FIN 47 as of December 31, 2005. See Note 12 of ComEd’s Notes to Consolidated Financial Statements for further discussion of the adoption of FIN 47.

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Electric Operating Statistics and Revenue Detail

Retail Deliveries—(in GWhs)	2005	2004	Variance		% Change
Full service(a)
Residential	30,042	26,463	3,579		13.5	%
Small commercial & industrial	21,378	21,662	(284	)	(1.3	%)
Large commercial & industrial	7,904	6,913	991		14.3	%
Public authorities & electric railroads	2,133	1,893	240		12.7	%
Total full service	61,457	56,931	4,526		7.9	%
PPO
Small commercial & industrial	5,591	4,110	1,481		36.0	%
Large commercial & industrial	6,004	5,377	627		11.7	%
	11,595	9,487	2,108		22.2	%
Delivery only(b)
Small commercial & industrial	5,677	6,305	(628	)	(10.0	%)
Large commercial & industrial	13,633	14,634	(1,001	)	(6.8	%)
	19,310	20,939	(1,629	)	(7.8	%)
Total PPO and delivery only	30,905	30,426	479		1.6	%
Total retail deliveries	92,362	87,357	5,005		5.7	%

(a) Full service reflects deliveries to customers taking electric service under tariffed rates.

(b) Delivery only service reflects customers electing to receive generation service from an alternative electric supplier.

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Electric Revenue	2005		2004		Variance			% Change
Full service(a)
Residential	$	2,584	$	2,295	$	289		12.6	%
Small commercial & industrial		1,671		1,649		22		1.3	%
Large commercial & industrial		408		380		28		7.4	%
Public authorities & electric railroads		132		126		6		4.8	%
Total full service		4,795		4,450		345		7.8	%
PPO(b)
Small commercial & industrial		385		274		111		40.5	%
Large commercial & industrial		345		304		41		13.5	%
		730		578		152		26.3	%
Delivery only(c)
Small commercial & industrial		95		128		(33	)	(25.8	%)
Large commercial & industrial		156		204		(48	)	(23.5	%)
		251		332		(81	)	(24.4	%)
Total PPO and delivery only		981		910		71		7.8	%
Total electric retail revenues		5,776		5,360		416		7.8	%
Wholesale and miscellaneous revenue(d)		488		443		45		10.2	%
Total operating revenues	$	6,264	$	5,803	$	461		7.9	%

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

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

(c) Delivery only revenues reflect revenue under tariff rates from customers electing to receive generation service from an alternative electric supplier, which includes a distribution charge and a CTC. Prior to ComEd’s full integration into PJM on May 1, 2004, ComEd’s transmission charges received from alternative electric suppliers were included in wholesale and miscellaneous revenue.

(d) Wholesale and miscellaneous revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales.

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Results of Operations—PECO

	2005			2004			Favorable (unfavorable) variance
Operating revenues	$	4,910		$	4,487		$	423
Operating expenses
Purchased power		2,515			2,172			(343	)
Operating and maintenance		549			547			(2	)
Depreciation and amortization		566			518			(48	)
Taxes other than income		231			236			5
Total operating expense		3,861			3,473			(388	)
Operating income		1,049			1,014			35
Other income and deductions
Interest expense		(280	)		(303	)		23
Equity in losses of unconsolidated affiliates		(16	)		(25	)		9
Other, net		14			18			(4	)
Total other income and deductions		(282	)		(310	)		28
Income before income taxes and cumulative effect of a change in accounting principle		767			704			63
Income taxes		247			249			2
Income before cumulative effect of a change in accounting principle		520			455			65
Cumulative effect of a change in accounting principle		(3	)		—			(3	)
Net income		517			455			62
Preferred stock dividends		4			3			(1	)
Net income on common stock	$	513		$	452		$	61

Net Income. PECO’s net income in 2005 increased primarily as a result of higher revenues, net of related purchased power expense, due to favorable weather and lower interest expense due to the scheduled retirement of debt owed to PETT, partially offset by higher CTC amortization.

Operating Revenues. The changes in PECO’s operating revenues for 2005 compared to 2004 consisted of the following:

	Electric			Gas			Total increase (decrease)
Rate changes and mix	$	72		$	90		$	162
Customer choice		118			—			118
Volume		101			(21	)		80
Weather		54			10			64
Retail revenue		345			79			424
T&O / SECA rates		3			—			3
PJM transmission		(3	)		—			(3	)
Other		9			(10	)		(1	)
Wholesale and miscellaneous revenues		9			(10	)		(1	)
Increase in operating revenues	$	354		$	69		$	423

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Rate changes and mix. The increase in electric revenues at PECO attributable to rate changes and mix resulted from increased residential sales, which are billed at higher average rates relative to other customer classes. In addition, rates were higher in 2005 for certain large commercial and industrial customers whose rates reflect wholesale energy prices, which were higher in 2005 relative to 2004.

The increase in gas revenues was due to increases in rates through PAPUC-approved changes to the purchased gas adjustment clause that became effective March 1, 2004, March 1, 2005, June 1, 2005, September 1, 2005 and December 1, 2005. The average purchased gas cost rate per million cubic feet in effect for 2005 was 12% higher than the average rate for 2004.

Customer choice. For 2005 and 2004, 5% and 12%, respectively, of energy delivered to PECO’s retail customers was provided by alternative electric suppliers.

All PECO customers have the choice to purchase energy from an alternative electric supplier. This choice does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation service. Operating income is not affected by customer choice since any increase or decrease in revenues is completely offset by any related increase or decrease in purchased power expense.

	2005		2004
Retail customers purchasing energy from an alternative electric supplier:
Number of customers at period end	44,500		101,500
Percentage of total retail customers	3	%	7	%
Volume (GWhs)(a)	2,094		4,605
Percentage of total retail deliveries	5	%	12	%

(a) One GWh is the equivalent of one million kilowatthours (kWh).

The increase in electric retail revenue associated with customer choice was primarily related to a significant number of residential customers returning to PECO as their energy provider in December 2004. This action followed the assignment of approximately 194,000 residential customers to alternative electric suppliers for a one-year term beginning in December 2003, as required by the PAPUC and PECO’s final electric restructuring order. In 2005, additional customers returned to PECO as their energy supplier primarily as a result of two alternative energy suppliers exiting the market.

Volume. The increase in electric revenues was primarily as a result of higher delivery volume, exclusive of the effects of weather and customer choice, due to an increased number of customers and increased usage per customer across all customer classes. The decrease in gas revenues attributable to lower delivery volume, exclusive of the effects of weather, was primarily due to decreased customer usage, which is consistent with rising gas prices.

Weather.The demand for electricity and gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and gas businesses, very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity and gas. Conversely, mild weather reduces demand. Revenues were positively affected by favorable weather conditions at PECO in 2005 compared to 2004. In the PECO service territory, cooling and heating degree days were 21% and 2% higher, respectively, than the prior year.

T&O / SECA rates. Effective December 1, 2004, PJM became obligated to pay SECA collections to PECO, and PECO became obligated to pay SECA charges—see “Purchased Power and Fuel Expense” below. The elimination of T&O revenues and inclusion of SECA revenues had a minimal

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impact on PECO as T&O revenues recognized in the past were not material and SECA revenues currently being recognized also are not material. See Note 2 of PECO’s Notes to Consolidated Financial Statements for more information on T&O / SECA rates.

Other wholesale and miscellaneous revenues. Electric revenues increased $9 million primarily due to increased wholesale sales, and gas revenues decreased $10 million primarily due to decreased off-system sales.

Purchased Power and Fuel Expense.The changes in PECO’s purchased power and fuel expense for 2005 compared to 2004 consisted of the following:

	Electric		Gas			Total increase (decrease)
Prices	$	83	$	90		$	173
Customer choice		118		—			118
Weather		21		7			28
Volume		32		(15	)		17
PJM transmission		11		—			11
SECA rates		9		—			9
Other		—		(13	)		(13	)
Increase in purchased power and fuel expense	$	274	$	69		$	343

Prices.PECO’s purchased power expense increased due to a change in the mix of average pricing related to its PPA with Generation. Fuel expense for gas increased due to higher gas prices. See “Operating Revenues” above.

Customer choice.The increase in purchased power expense from customer choice was primarily due to a significant number of residential customers returning to PECO as their energy provider in December 2004.

Weather.The increase in purchased power and fuel expense attributable to weather was primarily due to serving the increased demand due to favorable weather conditions in the PECO service territory.

Volume. The increase in purchased power expense attributable to volume, exclusive of the effects of weather and customer choice, was due primarily to an increased number of customers and increased usage per customer across all customer classes. The decrease in gas fuel expense attributable to volume, exclusive of the effects of weather, was due to decreased customer usage, which is consistent with rising gas prices.

SECA rates. Effective December 1, 2004, PJM became obligated to pay SECA collections to PECO, and PECO became obligated to pay SECA charges. During 2005 and 2004, PECO recorded SECA charges of $10 million and $1 million, respectively. See Note 2 of PECO’s Notes to Consolidated Financial Statements for more information on T&O /SECA rates.

Other. The decrease in gas fuel expense of $13 million was associated with decreased off-system sales.

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Operating and Maintenance Expense.The changes in operating and maintenance expense for the 2005 compared to 2004 consisted of the following:

	Increase (decrease)
Contractors(a)	$	8
Storm costs		7
Implementation of new customer information and billing system		4
PSEG merger integration costs		2
Severance-related expenses(b)		(14	)
Injuries and damages		(6	)
Other		1
Increase in operating and maintenance expense	$	2

(a) The increase was primarily due to increases in vegetation management services compared to the prior year at PECO.

(b) Consists of salary continuance severance costs, curtailment charges for pension and other post retirement benefits, and special termination benefit charges related to other postretirement benefits. The decrease reflects reduced severance-related activity in 2005 compared to 2004.

Depreciation and Amortization Expense.The changes in depreciation and amortization expense for 2005 compared to 2004 consisted of the following:

	Increase (decrease)
Competitive transition charge amortization	$	37
Accelerated amortization of PECO billing system		13
Depreciation expense		3
Other amortization expense		(5	)
Increase in depreciation and amortization expense	$	48

PECO’s additional amortization of the CTC is in accordance with its original settlement under the Pennsylvania Competition Act.

In January 2005, as part of a broader systems strategy at PECO associated with the pending merger with PSEG, Exelon’s Board of Directors approved the implementation of a new customer information and billing system at PECO. The approval of this new system requires the accelerated amortization of PECO’s current system through 2006 and the recognition of additional amortization expense of $13 million and $10 million in 2005 and 2006, respectively. If additional system changes are approved, additional accelerated depreciation may be required.

The increase in depreciation expense is primarily due to capital additions.

Taxes Other Than Income.The changes in taxes other than income for 2005 compared to 2004 consisted of the following:

	Increase (decrease)
Reduction in capital stock tax accrual in 2005(a)	$	(17	)
Reduction in real estate tax accrual in 2005(b)		(6	)
Taxes on utility revenues(c)		24
Other		(6	)
Decrease in taxes other than income	$	(5	)

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(a) Represents a reduction in 2005 of prior year capital stock tax accruals as a result of a favorable decision from the Pennsylvania Board of Finance and Revenue.

(b) Represents the reduction of a real estate tax accrual in March 2005 following settlements between PECO and various taxing authorities related to prior year tax assessments. See Note 15 of PECO’s Notes to the Financial Statements for additional information.

(c) As these taxes were collected from customers and remitted to the taxing authorities and included in revenues and expenses, the increase in tax expense was offset by a corresponding increase in revenues.

Interest Expense.The reduction in interest expense at PECO of $23 million for 2005 compared to 2004 was primarily due to scheduled payments on long-term debt owed to PETT.

Equity in Losses of Unconsolidated Affiliates.The decrease in equity in losses of unconsolidated affiliates was a result of a decrease in interest expense of the deconsolidated financing trusts of PECO due to scheduled repayments of outstanding long-term debt.

Income Taxes. PECO’s effective income tax rate was 32.2% for 2005 compared to 35.4% for 2004. The decrease in the effective tax rate was primarily attributable to a state income tax benefit recorded as a result of the favorable settlement of a 2000 Pennsylvania corporate net income tax audit. See Note 8 of PECO’s Notes to Consolidated Financial Statements for further details of the components of the effective income tax rates.

Cumulative Effect of a Change in Accounting Principle. The cumulative effect of a change in accounting principle reflects the impact of adopting FIN 47 as of December 31, 2005. See Note 10 of PECO’s Notes to Consolidated Financial Statements for further discussion of the adoption of FIN 47.

PECO Electric Operating Statistics and Revenue Detail

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

Retail Deliveries—(in GWhs)	2005	2004	Variance		% Change
Full service(a)
Residential	13,135	10,349	2,786		26.9	%
Small commercial & industrial	7,263	6,728	535		8.0	%
Large commercial & industrial	15,205	14,908	297		2.0	%
Public authorities & electric railroads	962	914	48		5.3	%
Total full service	36,565	32,899	3,666		11.1	%
Delivery only(b)
Residential	334	2,158	(1,824	)	(84.5	%)
Small commercial & industrial	1,257	1,687	(430	)	(25.5	%)
Large commercial & industrial	503	760	(257	)	(33.8	%)
Total delivery only	2,094	4,605	(2,511	)	(54.5	%)
Total retail deliveries	38,659	37,504	1,155		3.1	%

(a) Full service reflects deliveries to customers taking electric service under tariffed rates.

(b) Delivery only service reflects customers receiving electric generation service from an alternative electric supplier.

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Electric Revenue	2005		2004		Variance			% Change
Full service(a)
Residential	$	1,705	$	1,317	$	388		29.5	%
Small commercial & industrial		818		756		62		8.2	%
Large commercial & industrial		1,173		1,113		60		5.4	%
Public authorities & electric railroads		84		80		4		5.0	%
Total full service		3,780		3,266		514		15.7	%
Delivery only(b)
Residential		25		164		(139	)	(84.8	%)
Small commercial & industrial		63		86		(23	)	(26.7	%)
Large commercial & industrial		13		20		(7	)	(35.0	%)
Total delivery only		101		270		(169	)	(62.6	%)
Total electric retail revenues		3,881		3,536		345		9.8	%
Miscellaneous revenue(c)		212		203		9		4.4	%
Total electric and other revenue	$	4,093	$	3,739	$	354		9.5	%

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

(b) Delivery only revenue reflects revenue from customers receiving generation service from an alternative electric supplier, which includes a distribution charge and a CTC.

(c) Miscellaneous revenues include transmission revenue from PJM and other wholesale energy sales.

PECO’s Gas Sales Statistics and Revenue Detail

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

Deliveries to customers (in million cubic feet (mmcf))	2005		2004		Variance			% Change
Retail sales		59,751		59,949		(198	)	(0.3	%)
Transportation		25,310		27,148		(1,838	)	(6.8	%)
Total		85,061		87,097		(2,036	)	(2.3	%)
Revenue	2005		2004		Variance			% Change
Retail sales	$	783	$	702	$	81		11.5	%
Transportation		16		18		(2	)	(11.1	%)
Resales and other		18		28		(10	)	(35.7	%)
Total gas revenue	$	817	$	748	$	69		9.2	%

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Results of Operations—Generation

	2005			2004			Favorable (unfavorable) variance
Operating revenues	$	9,046		$	7,703		$	1,343
Operating expenses
Purchased power		2,569			2,307			(262	)
Fuel		1,913			1,704			(209	)
Operating and maintenance		2,288			2,201			(87	)
Depreciation and amortization		254			286			32
Taxes other than income		170			166			(4	)
Total operating expenses		7,194			6,664			(530	)
Operating income		1,852			1,039			813
Other income and deductions
Interest expense		(128	)		(103	)		(25	)
Equity in losses of unconsolidated affiliates		(1	)		(14	)		13
Other, net		95			130			(35	)
Total other income and deductions		(34	)		13			(47	)
Income from continuing operations before income taxes and minority interest		1,818			1,052			766
Income taxes		709			401			(308	)
Income from continuing operations before minority interest		1,109			651			458
Minority interest		—			6			(6	)
Income from continuing operations		1,109			657			452
Discontinued operations
Loss from discontinued operations		—			(45	)		45
Gain on disposal of discontinued operations		24			—			24
Income taxes		5			(29	)		(34	)
Income (loss) from discontinued operations		19			(16	)		35
Income before cumulative effect of changes in accounting principles		1,128			641			487
Cumulative effect of changes in accounting principles		(30	)		32			(62	)
Net income	$	1,098		$	673		$	425

Net Income. Generation’s net income in 2005 increased $425 million as compared to the prior year, primarily as a result of higher revenue, net of purchased power and fuel expense, partially offset by higher operating and maintenance expense and interest expense. Generation’s revenue, net of purchased power and fuel expense, increased $872 million in 2005 as compared to the prior year. This increase was driven by the contractual increase in prices associated with Generation’s power sales agreement with ComEd and higher average margins on wholesale market sales as higher spot market prices more than compensated for higher fuel prices and the impact of higher nuclear generation.

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Operating Revenues.For 2005 and 2004, Generation’s sales were as follows:

Revenue	2005		2004		Variance		% Change
Electric sales to affiliates	$	4,775	$	3,749	$	1,026	27.4	%
Wholesale and retail electric sales		3,341		3,227		114	3.5	%
Total energy sales revenue		8,116		6,976		1,140	16.3	%
Retail gas sales		613		448		165	36.8	%
Trading portfolio		17		—		17	n.m.
Other revenue(a)		300		279		21	7.5	%
Total revenue	$	9,046	$	7,703	$	1,343	17.4	%

(a) Includes sales related to tolling agreements, fossil fuel sales and decommissioning revenue from ComEd and PECO.

n.m. Not meaningful

Sales (in GWhs)	2005	2004	Variance		% Change
Electric sales to affiliates	121,961	110,465	11,496		10.4	%
Wholesale and retail electric sales	72,376	92,134	(19,758	)	(21.4	)%
Total sales	194,337	202,599	(8,262	)	(4.1	)%

Trading volumes of 26,924 GWhs and 24,001 GWhs for 2005 and 2004, respectively, are not included in the table above.

Electric sales to affiliates.Revenue from sales to affiliates increased $1,026 million in 2005 as compared to the prior year. The increase in revenue from sales to affiliates was primarily due to a $635 million increase from overall higher prices associated with Generation’s PPA with ComEd and a $391 million increase from higher electric sales volume. As a result of the Amended and Restated Purchase Power Agreement as of April 30, 2004 with ComEd, effective January 1, 2005, Generation began receiving overall higher prices from ComEd for its purchased power. The higher sales volumes to ComEd and PECO resulted from favorable weather conditions in the summer and winter periods in the ComEd and PECO service territories and an increase in the number of customers returning from alternative electric suppliers in 2005 compared to the prior year.

Wholesale and retail electric sales.The changes in Generation’s wholesale and retail electric sales for 2005 compared to 2004 consisted of the following:

	Increase (decrease)
Price	$	879
Volume		(526	)
Sale of Boston Generating		(239	)
Increase in wholesale and retail electric sales	$	114

(a) Sales to Boston Generating of $9 million were included in other revenue for 2004.

Wholesale and retail sales increased $114 million due to an increase in market prices in 2005 compared to the prior year. The increase in market prices was primarily driven by higher fuel prices (e.g. oil and natural gas). The increase in price was partially offset by lower volumes of generation capacity sold to the market in 2005 as compared to 2004. Generation had less power to sell into the market as a result of higher demand for power sold to affiliates in 2005 and the expiration of its purchase power agreement with Midwest Generation in 2004. The remaining decrease in wholesale and retail sales of $239 million was due to the sale of Boston Generating in May 2004.

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Retail gas sales.Retail gas sales increased $165 million primarily due to significantly higher gas prices in the overall market.

Trading portfolio.Trading portfolio income increased $17 million in 2005 compared to the prior year due to an increase in trading volumes. See ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk—Proprietary Trading Activities for further information.

Other revenues. The increase in other revenues in 2005 was primarily due to an increase of $60 million associated with revenue from Generation’s operating services agreements with PSEG and Tamuin International, Inc. This increase was partially offset by a decrease of $39 million related to lower fuel sales, a reduction in decommissioning revenue from ComEd and lower sales from tolling and gas management agreements. The increased revenue from the operating services agreements was substantially offset by a corresponding increase in Generation’s operating and maintenance expense.

Purchased Power and Fuel Expense.Generation’s supply sources are summarized below:

Supply Source (in GWhs)	2005	2004	Variance		% Change
Nuclear generation(a)	137,936	136,621	1,315		1.0	%
Purchases—non-trading portfolio	42,623	48,968	(6,345	)	(13.0	)%
Fossil and hydroelectric generation(b)	13,778	17,010	(3,232	)	(19.0	)%
Total supply	194,337	202,599	(8,262	)	(4.1	)%

(a) Represents Generation’s proportionate share of the output of its nuclear generating plants.

(b) Fossil and hydroelectric generation decreased by 4,978 GWhs as a result of lower fossil fuel generation due to the sale of Boston Generating in May 2004.

The changes in Generation’s purchased power and fuel expense for 2005 compared to 2004 consisted of the following:

	Increase (decrease)
Price	$	845
Volume		(93	)
Mark-to-market		9
Sale of Boston Generating		(226	)
Other		(64	)
Increase in purchased power and fuel expense	$	471

Price. The increase reflects overall higher market energy prices for purchased power and higher natural gas and oil prices in 2005 as compared to the prior year. The increase in unplanned outages in 2005 occurred during periods of higher energy prices, which caused Generation to purchase power in the market at high prices. Additionally, overall energy market conditions resulted in higher prices for raw materials (i.e., oil, gas and coal) used in the production of electricity. These factors contributed to an increase in the average purchase power costs of approximately $13 per MWh for 2005.

Volume. The reduced volume in 2005 as compared to 2004 was primarily due to lower volumes of purchased power in the market slightly offset by higher nuclear and fossil generation needed to meet ComEd’s and PECO’s load requirements.

Mark-to-market.Mark-to-market losses on hedging activities were $12 million for 2005 compared to losses of $3 million for 2004.

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Boston Generating.The decrease in purchased power and fuel expense associated with Boston Generating was due to the sale of the business in May 2004.

Other. Other decreases in purchased power and fuel expense were primarily due to lower transmission expense in 2005 as compared to the prior year resulting from the expansion of the PJM region due to new transmission owners joining PJM and reduced inter-region transmission charges, primarily associated with ComEd’s integration into PJM on May 1, 2004.

Generation’s average margin per MWh of electricity sold for 2005 and 2004 was as follows:

($/MWh)	2005		2004		% Change
Average electric revenue
Electric sales to affiliates(a)	$	39.15	$	33.94	15.4	%
Wholesale and retail electric sales		46.16		35.03	31.8	%
Total—excluding the trading portfolio		41.76		34.43	21.3	%
Average electric supply cost(b)—excluding the trading portfolio	$	20.11	$	17.60	14.3	%
Average margin—excluding the trading portfolio	$	21.65	$	16.83	28.6	%

(a) The increase in $/MWh is due to higher prices in 2005 associated with Generation’s PPA with ComEd.

(b) Average supply cost includes purchased power and fuel costs associated with electric sales. Average electric supply cost does not include fuel costs associated with retail gas sales.

Nuclear fleet operating data and purchased power cost data for 2005 and 2004 were as follows:

	2005			2004
Nuclear fleet capacity factor(a)		93.5	%		93.5	%
Nuclear fleet production cost per MWh(a)	$	13.03		$	12.43
Average purchased power cost for wholesale operations per MWh	$	60.27		$	47.11

(a) Excludes Salem, which is operated by PSEG Nuclear.

The nuclear fleet capacity factor was the same in 2005 as compared to 2004. Higher costs associated with the planned refuel outages and higher non-outage operating costs resulted in a higher production cost per MWh produced for 2005 as compared to 2004. There were nine planned refueling outages and 25 non-refueling outages in 2005 compared to nine planned refuel outages and 20 non-refueling outages in 2004.

During 2004, both Quad Cities’ units operated intermittently at Extended Power Uprate (EPU) generation levels due to performance issues with their steam dryers. As of the third quarter of 2005, both of the Quad Cities’ units returned to EPU generation levels after extensive testing and load verification on new replacement steam dryers was completed. Near the end of 2005, the generation levels of both Quad Cities’ units were again reduced to pre-EPU generation levels to address vibration–related equipment issues not directly related to the steam dryers. The units will be brought back to full EPU generation levels after all issues are addressed to ensure safe and reliable operations at the EPU output levels which is expected to occur in 2006.

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Operating and Maintenance Expense.The increase in operating and maintenance expense for 2005 compared to 2004 consisted of the following:

	Increase (decrease)
Nuclear refueling and non-outage operating costs	$	78
DOE Settlement in 2004		42
Tamuin International		44
Accrual for estimated future asbestos-related bodily injury claims		43
Nuclear operating services agreement		14
Pension, payroll and benefit costs		(58	)
Boston Generating		(62	)
Decommissioning-related activity		(38	)
Other		24
Increase in operating and maintenance expense	$	87

This net $87 million increase is attributable to the following:

• A $78 million increase in nuclear refueling and non-outage operating costs due to an increase in nuclear maintenance costs of $44 million related to planned nuclear refueling outages for plants operated by Generation and the co-owned Salem Generating Station, and increases in other nuclear operating and maintenance expenses of $34 million, primarily security and inflationary costs;

• A $42 million reimbursement in 2004 of costs incurred prior to 2004 for the storage of spent nuclear fuel associated with the DOE Settlement Agreement;

• A $44 million increase in expenses associated with Generation’s operating service agreement with a subsidiary of Tamuin International, Inc;

• The establishment of a $43 million liability in June 2005 for estimated future asbestos-related bodily injury claims (see further discussion in Note 17 to Generation’s Notes to Consolidated Financial Statements); and

• Costs of $14 million in 2005 associated with the Salem and Hope Creek Operating Services Agreement with PSEG, the reimbursement of which is included in other revenues.

The increases in operating and maintenance expense described above were partially offset by lower payroll-related expenses (a $58 million reduction), the elimination of $62 million in expenses at Boston Generating due to its sale in May 2004 and a $36 million reduction in the contractual obligation that Generation has to ComEd related to decommissioning obligations (which is included in the $38 million of decommissioning-related activity in the table above).

Depreciation and Amortization.The decrease in depreciation and amortization expense for 2005 compared to 2004 was primarily due to the establishment of an ARC asset for retired nuclear units of $36 million recorded in the third quarter of 2004 which was immediately impaired through depreciation expense as this asset was associated with retired nuclear units that do not have any remaining useful life. This decrease was partially offset by increased depreciation expense due to recent capital additions.

Taxes Other Than Income.The increase in taxes other than income for 2005 as compared to 2004 was primarily due to a net increase in Generation’s reserves related to payroll taxes, sales and use taxes and other taxes other than income, partially offset by a reduction in taxes resulting from the sale of Boston Generating in May 2004.

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Other, Net.The decrease in other income for 2005 as compared to the prior year was primarily due to the $85 million gain ($52 million, net of taxes) on the disposal of Boston Generating recorded in May 2004, partially offset by gains of $36 million realized in the second quarter of 2005 related to the decommissioning trust fund investments for the AmerGen plants, primarily associated with changes in Generation’s investment strategy.

Effective Income Tax Rate.The effective income tax rate from continuing operations was 39.0% for 2005 compared to 38.1% for 2004. See Note 12 of Generation’s Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

Discontinued Operations.On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. In addition, Generation has sold or wound down substantially all components of AllEnergy, a business within Exelon Energy. Accordingly, the results of operations and the gain on the sale of Sithe and results of AllEnergy have been presented as discontinued operations for 2005 within Generation’s Consolidated Statements of Income. See Notes 2 and 3 of Generation’s Notes to Consolidated Financial Statements for further information regarding the presentation of Sithe’s and AllEnergy’s results of operations as discontinued operations and the sale of Sithe as discontinued operations.

Cumulative Effect of Changes in Accounting Principles. The cumulative effect of changes in accounting principles reflects the impact of adopting FIN 47 as of December 31, 2005 and the consolidation of Sithe in accordance with FIN 46-R as of March 31, 2004. See Notes 1 and 14 of Generation’s Notes to Consolidated Financial Statements for further discussion of the consolidation of Sithe and the adoption of FIN 47, respectively.

Year Ended December 31, 2004 Compared To Year Ended December 31, 2003

Significant Operating Trends—Exelon

Exelon Corporation	2004			2003			Favorable (unfavorable) variance
Operating revenues	$	14,133		$	15,148		$	(1,015	)
Purchased power and fuel expense		4,929			6,194			1,265
Operating and maintenance expense		3,700			3,915			215
Impairment of Boston Generating, LLC long-lived assets		—			945			945
Depreciation and amortization		1,295			1,115			(180	)
Operating income		3,499			2,409			1,090
Other income and deductions		(922	)		(1,123	)		201
Income from continuing operations before income taxes and minority interest		2,577			1,286			1,291
Income taxes		713			389			(324	)
Income from continuing operations		1,870			892			978
Loss from discontinued operations, net of income taxes		(29	)		(99	)		70
Income before cumulative effect of changes in accounting principles		1,841			793			1,048
Cumulative effect of changes in accounting principles		23			112			(89	)
Net income		1,864			905			959
Diluted earnings per share		2.78			1.38			1.40

Net Income.Net income for 2004 reflects income of $32 million for the adoption of FIN 46-R, partially offset by a loss of $9 million related to the adoption of Emerging Issues Task Force (EITF)

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Issue No. 03-16, “Accounting for Investments in Limited Liability Companies” (EITF 03-16). Net income for 2003 reflects income of $112 million for the adoption of SFAS No. 143. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the adoptions of FIN 46-R, EITF 03-16 and SFAS No. 143.

Operating Revenues.Operating revenues decreased primarily due to decreased revenues at Enterprises due to the sale of InfraSource in 2003, the sale of Boston Generating in 2004 and Generation’s adoption of EITF 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) in the first quarter of 2004, which changed the presentation of certain power transactions and decreased 2004 operating revenues by $980 million. The adoption of EITF 03-11 had no impact on net income. Operating revenues were favorably affected by Generation’s acquisition of the remaining 50% of AmerGen in 2003. Operating revenues were also favorably affected by increased volume growth and transmission revenues at ComEd and PECO collected from PJM, partially offset by unfavorable weather conditions and customer choice initiatives. See further discussion of operating revenues by segment below.

Purchased Power and Fuel Expense.Purchased power and fuel expense decreased primarily due to Generation’s adoption of EITF 03-11 during 2004 which resulted in a decrease in purchased power expense and fuel expense of $980 million. In addition, purchased power decreased due to Generation’s acquisition of the remaining 50% of AmerGen in 2003, which was only partially offset by an increase in fuel expense, and the sale of Boston Generating in 2004. Purchased power represented 24% of Generation’s total supply in 2004 compared to 37% in 2003. Purchased power also decreased at ComEd and PECO due to unfavorable weather conditions and customer choice. See further discussion of purchased power and fuel expense by segment below.

Impairment of the Long-Lived Assets of Boston Generating. Generation recorded a $945 million charge (before income taxes) during 2003 to impair the long-lived assets of Boston Generating.

Operating and Maintenance Expense.Operating and maintenance expense decreased primarily as a result of decreased expenses at InfraSource due to its sale in 2003 and decreased severance and severance-related expenses, partially offset by increased expenses at Generation due to the acquisition of the remaining 50% of AmerGen. Operating and maintenance expense increased $65 million due to investments in synthetic fuel-producing facilities made in the fourth quarter of 2003 and the third quarter of 2004. See further discussion of operating and maintenance expenses by segment below.

Depreciation and Amortization Expense. The increase in depreciation and amortization expense was primarily due to additional plant placed in service at ComEd, PECO and Generation, the acquisition of the remaining 50% in AmerGen in 2003 and the establishment of an ARC asset for retired nuclear units in 2004 which was immediately impaired through depreciation expense in 2004. The increase also resulted from increased amortization expense due to investments made in the fourth quarter of 2003 and the third quarter of 2004 in synthetic fuel-producing facilities and increased competitive transition charge amortization at PECO. These increases were partially offset by reduced depreciation and amortization expense at Enterprises due to the sale of InfraSource in 2003.

Operating Income.Exclusive of the changes in operating revenues, purchased power and fuel expense, the impairment of Boston Generating’s long-lived assets, operating and maintenance expense and depreciation and amortization expense discussed above, the change in operating income was primarily the result of increased taxes other than income in 2004 as compared to 2003, primarily due to the reduction of certain real estate tax accruals at PECO and Generation during 2003.

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Other Income and Deductions. Other income and deductions in 2004 reflects interest expense of $828 million, equity in losses of unconsolidated affiliates of $154 million, debt retirement charges of $130 million (before income taxes) recorded at ComEd associated with an accelerated liability management plan, and an $85 million gain (before income taxes) on the 2004 sale of Boston Generating. Other income and deductions in 2003 reflects interest expense of $873 million and impairment charges of $255 million (before income taxes) related to Generation’s investment in Sithe. Equity in earnings of unconsolidated affiliates decreased by $187 million due to the acquisition of the remaining 50% of AmerGen in 2003, the deconsolidation of certain financing trusts during 2003 and investments in synthetic fuel-producing facilities made in the fourth quarter of 2003 and the third quarter of 2004.

Effective Income Tax Rate.The effective income tax rate from continuing operations was 28% for 2004 compared to 30% for 2003. The decrease in the effective rate was primarily attributable to investments in synthetic fuel-producing facilities made in the fourth quarter of 2003.

Discontinued Operations.2004 and 2003 discontinued operations consist of Sithe’s 2004 results (beginning April 1, 2004), certain qualifying components of Enterprises, and AllEnergy. AllEnergy is a business within Exelon Energy, which is a business within Generation. A discussion of the results of Sithe and AllEnergy is included in the Generation segment results discussion below. Enterprises’ after-tax loss from discontinued operations of $78 million in 2003 and $13 million in 2004 decreased by $65 million primarily due to a 2004 gain on the sale of the Chicago operations of Thermal and a decrease in operating and maintenance expense of $401 million, partially offset by a decrease in revenues. At December 31, 2004, the remaining assets of the businesses associated with the former Enterprises segment totaled approximately $274 million in comparison to $697 million at December 31, 2003.

Results of Operations by Business Segment

Historically, Exelon had reported Enterprises as a segment. Exelon sold or unwound substantially all components of Enterprises in 2004 and 2003. As a result, Enterprises is no longer reported as a segment and is included within the “other” category within the results of operations by business segment below. Other consists of corporate operations, including Exelon Business Services Company, Enterprises and investments in synthetic fuel-producing facilities.

The comparison of 2004 and 2003 operating results and other statistical information set forth below include intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.

Transfer of Exelon Energy Company from Enterprises to Generation.Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, was transferred to Generation. The 2003 information related to the Generation segment discussed below has been adjusted to reflect the transfer of Exelon Energy Company from Enterprises to the Generation segment. Exelon Energy Company’s 2003 results, excluding intercompany eliminations, were as follows:

Total revenues	$	660
Intersegment revenues		4
Operating revenues and purchased power from affiliates		200
Depreciation and amortization		1
Operating expenses		648
Interest expense		1
Income from continuing operations before income taxes		6
Income taxes		3
Income from continuing operations		3
Loss from discontinued operations, net of income taxes		(21	)
Net loss		(18	)

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Income (Loss) from Continuing Operations

	2004		2003			Favorable (unfavorable) variance
ComEd	$	676	$	702		$	(26	)
PECO		455		473			(18	)
Generation		657		(238	)		895
Other		82		(45	)		127
Total	$	1,870	$	892		$	978

Income (Loss) Before Cumulative Effect of Changes in Accounting Principles by Business Segment

	2004		2003			Favorable (unfavorable) variance
ComEd	$	676	$	702		$	(26	)
PECO		455		473			(18	)
Generation		641		(259	)		900
Other		69		(123	)		192
Total	$	1,841	$	793		$	1,048

Net Income (Loss) by Business Segment

	2004		2003			Favorable (unfavorable) variance
ComEd	$	676	$	707		$	(31	)
PECO		455		473			(18	)
Generation		673		(151	)		824
Other		60		(124	)		184
Total	$	1,864	$	905		$	959

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Results of Operations—ComEd

	2004			2003			Favorable (unfavorable) variance
Operating revenues	$	5,803		$	5,814		$	(11	)
Operating expenses
Purchased power		2,588			2,501			(87	)
Operating and maintenance		897			1,093			196
Depreciation and amortization		410			386			(24	)
Taxes other than income		291			267			(24	)
Total operating expense		4,186			4,247			61
Operating income		1,617			1,567			50
Other income and deductions
Interest expense		(369	)		(423	)		54
Distributions on mandatorily redeemable preferred securities		—			(26	)		26
Equity in losses of unconsolidated affiliates		(19	)		—			(19	)
Net loss on extinguishment of long-term debt		(130	)		—			(130	)
Other, net		34			49			(15	)
Total other income and deductions		(484	)		(400	)		(84	)
Income before income taxes and cumulative effect of a change in accounting principle		1,133			1,167			(34	)
Income taxes		457			465			8
Income before cumulative effect of a change in accounting principle		676			702			(26	)
Cumulative effect of a change in accounting principle		—			5			(5	)
Net Income	$	676		$	707		$	(31	)

Net Income. ComEd’s net income in 2004 decreased primarily due to costs associated with ComEd’s accelerated retirement of long-term debt, partially offset by higher operating income. The decrease in operating and maintenance expense was primarily driven by lower severances charges.

Operating Revenues. The changes in operating revenues for 2004 compared to the 2003 consisted of the following:

	Increase (decrease)
Weather	$	(113	)
Customer choice		(104	)
Rate changes and mix		(75	)
Volume		178
Retail revenue		(114	)
PJM transmission		164
T&O charges		(41	)
Other		(20	)
Wholesale and miscellaneous revenues		103
Decrease in operating revenues	$	(11	)

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Weather.The weather impact for the year ended December 31, 2004 was unfavorable compared to the same period in 2003 as a result of milder weather in 2004. Cooling degree-days decreased 12% and heating degree-days decreased 6% in the year ended December 31, 2004 compared to the same period in 2003.

Customer Choice. All ComEd customers have the choice to purchase energy from an alternative electric supplier. 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, 2004, no alternative electric supplier had approval from the ICC, and no electric utilities had chosen, to enter the ComEd residential market for the supply of electricity.

	2004		2003
Retail customers purchasing energy from an alternative electric supplier:
Volume (GWhs)(a)	20,939		17,317
Percentage of total retail deliveries	24	%	20	%
Retail customers purchasing energy from an alternative electric supplier or the ComEd PPO:
Number of customers at period end	22,161		20,300
Percentage of total retail customers	(b	)	(b	)
Volume (GWhs)(a)	30,426		26,908	��
Percentage of total retail deliveries	35	%	31	%

(a) One GWh is the equivalent of one million kilowatthours (kWh).

(b) Less than one percent.

Rate Changes and Mix. In addition to a change in revenue from the change in rate mix due to changes in monthly usage patterns in all customer classes during 2004 compared to 2003, revenue changed as a result of rate changes. Starting in the June 2003 billing cycle, the increased wholesale market price of electricity and other adjustments to the energy component, decreased the collection of CTCs as compared to the respective prior year period. ComEd’s CTC revenues decreased by $135 million for the year ended December 31, 2004 as compared to the same period in 2003. This decrease was partially offset by increased wholesale market prices which increased energy revenue received under the ComEd PPO and by increased average rates, resulting from a change in customer usage, paid by small and large commercial and industrial customers totaling $53 million. For the years ended December 31, 2004 and December 31, 2003, ComEd collected $169 million and $304 million, respectively, of CTC revenue. Under the current restructuring statute, no CTCs will be collected after 2006.

Volume.ComEd’s electric revenues from higher delivery volume, exclusive of effects of weather and customer choice, increased due to an increased number of customers and increased usage per customer, generally across all customer classes.

PJM transmission.ComEd’s transmission revenues and purchased power expense each increased by $164 million due to ComEd’s May 1, 2004 entry into PJM.

T&O Charges. Prior to FERC orders issued in November 2004, ComEd collected T&O charges for energy flowing across ComEd’s transmission system. Charges collected as the transmission owner were recorded in operating revenues. In addition after ComEd joined PJM on May 1, 2004, PJM allocated T&O collections to ComEd as a load serving entity. The collections received as a load serving entity were recorded as a decrease to purchased power expense. See Note 3 of ComEd’s Notes to Consolidated Financial Statements for more information on T&O charges.

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Purchased Power Expense.The changes in ComEd’s purchased power expense for 2004 compared to 2003 consisted of the following:

	Increase (decrease)
PJM transmission	$	164
Volume		94
PJM administrative fees		15
Customer choice		(87	)
Weather		(57	)
T&O charges		(22	)
Prices		(7	)
Other		(13	)
Increase in purchased power expense	$	87

PJM transmission.ComEd’s transmission revenues and purchased power expense each increased by $164 million due to ComEd’s May 1, 2004 entry into PJM. See “Operating Revenues” above.

Volume.ComEd’s purchased power expense increased due to increases, exclusive of the effects of weather and customer choice, in the number of customers and average usage per customer, generally across all customer classes.

PJM administrative fees.ComEd began paying PJM administrative fees upon its full integration into PJM on May 1, 2004.

Customer choice.An increase in customer switching resulted in a reduction of purchased power expense, primarily due to ComEd’s non-residential customers electing to purchase energy from an alternative electric supplier.

Weather.ComEd’s purchased power expense decreased due to unfavorable weather conditions.

T&O changes. Prior to FERC orders issued in November 2004, ComEd collected T&O charges for energy flowing across ComEd’s transmission system. Charges collected as the transmission owner were recorded in operating revenues. In addition, after ComEd joined PJM on May 1, 2004, PJM allocated T&O collections to ComEd as a load serving entity. The collections received as a load serving entity were recorded as a decrease to purchased power expense. See Note 3 of ComEd’s Notes to Consolidated Financial Statements for more information on T&O charges.

Prices.ComEd’s purchased power expense increased due to a change in the mix of average pricing related to ComEd’s PPAs with Generation.

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Operating and Maintenance Expense.The changes in operating and maintenance expense for the 2004 compared to 2003 consisted of the following:

	Increase (decrease)
Severance-related expenses	$	(115	)
Charge recorded at ComEd in 2003(a)		(41	)
Payroll expense(b)		(25	)
Contractors		(18	)
FERC annual fees(c)		(11	)
Environmental charges		(10	)
Allowance for uncollectible accounts expense		(9	)
Incremental storm costs		(7	)
Corporate allocations(d)		43
Other		(3	)
Decrease in operating and maintenance expense	$	(196	)

(a) In 2003, ComEd reached an agreement with various Illinois retail market participants and other interested parties.

(b) Due to fewer employees in 2004 compared to 2003.

(c) After joining PJM on May 1, 2004, ComEd is no longer directly charged annual fees by the FERC. PJM pays the annual FERC fees.

(d) Higher corporate allocations primarily result from centralization of information technology, supply, human resources, communications, and finance functions into BSC from all of the Exelon operating companies, and changes in the corporate governance allocation calculation. Corporate governance allocations increased overall as a result of higher centralized costs distributed out of BSC, the sale of the Enterprises companies resulting in ComEd comprising a greater base percentage of Exelon, and an SEC-mandated change to the methodology used to allocate Exelon’s corporate governance costs.

Depreciation and Amortization Expense.The changes in depreciation and amortization expense for 2004 compared to 2003 consisted of the following:

	Increase (decrease)
Depreciation expense	$	21
Other amortization expense		3
Increase in depreciation and amortization expense	$	24

ComEd’s increase in depreciation expense is primarily due to capital additions. Recoverable transition costs amortization remained constant in 2004 as compared to 2003.

Taxes Other Than Income.The increase was primarily attributable to a $25 million credit in 2003 for use tax payments for periods prior to the PECO / Unicom Merger and a refund of $5 million for Illinois Electricity Distribution taxes in 2003 partially offset by a refund of $8 million for Illinois Electricity Distribution taxes in 2004.

Interest Expense.The reduction in interest expense was primarily due to scheduled principal payments, debt retirements and prepayments, and refinancings at lower rates.

Equity in Losses of Unconsolidated Affiliates.During 2004, ComEd recorded $19 million of equity in net losses of subsidiaries as a result of ComEd deconsolidating their financing trusts.

Net Loss on Extinguishment of Long-Term Debt. In 2004, Exelon initiated an accelerated liability management plan at ComEd that resulted in the retirement of approximately $768 million of long-term debt, of which $618 million was retired during the third quarter of 2004. During 2004, ComEd

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recorded a charge of $130 million associated with the retirement of debt under the plan. The components of this charge included the following: $86 million related to prepayment premiums; $12 million related to net unamortized premiums, discounts and debt issuance costs; $24 million of losses on reacquired debt previously deferred as regulatory assets; and $12 million related to settled cash-flow interest-rate swaps previously deferred as regulatory assets partially offset by $4 million of unamortized gain on settled fair value interest-rate swaps.

Other, net. The change in other, net primarily results from the reversal of a $12 million reserve for potential plant disallowance in 2003 as a result of an agreement with various Illinois retail market participants and other interested parties, a reduction of AFDUC equity of $5 million during 2004 as a result of lower construction work in process balances and a $5 million decrease in interest income on the long-term receivable from UII, LLC (formerly Unicom Investments, Inc.) as a result of a lower principal balance, which were partially offset by various other items.

Income Taxes. ComEd’s effective income tax rate was 40.3% for 2004 and 39.8% 2003. See Note 10 of ComEd’s Notes to Consolidated Financial Statements for further details of the components of the effective income tax rates.

ComEd Electric Operating Statistics and Revenue Detail

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

Retail Deliveries—(in GWhs)	2004	2003	Variance		% Change
Full service(a)
Residential	26,463	26,206	257		1.0	%
Small commercial & industrial	21,662	23,334	(1,672	)	(7.2	%)
Large commercial & industrial	6,913	6,955	(42	)	(0.6	%)
Public authorities & electric railroads	1,893	2,297	(404	)	(17.6	%)
Total full service	56,931	58,792	(1,861	)	(3.2	%)
PPO
Small commercial & industrial	4,110	3,912	198		5.1	%
Large commercial & industrial	5,377	5,677	(300	)	(5.3	%)
	9,487	9,589	(102	)	(1.1	%)
Delivery only(b)
Small commercial & industrial	6,305	5,210	1,095		21.0	%
Large commercial & industrial	14,634	12,110	2,524		20.8	%
	20,939	17,320	3,619		20.9	%
Total PPO and delivery only	30,426	26,909	3,517		13.1	%
Total retail deliveries	87,357	85,701	1,656		1.9	%

(a) Full service reflects deliveries to customers taking electric service under tariffed rates.

(b) Delivery only service reflects customers electing to receive generation service from an alternative electric supplier.

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Electric Revenue	2004		2003		Variance			% Change
Full service(a)
Residential	$	2,295	$	2,272	$	23		1.0	%
Small commercial & industrial		1,649		1,720		(71	)	(4.1	%)
Large commercial & industrial		380		413		(33	)	(8.0	%)
Public authorities & electric railroads		126		153		(27	)	(17.6	%)
Total full service		4,450		4,558		(108	)	(2.4	%)
PPO(b)
Small commercial & industrial		274		256		18		7.0	%
Large commercial & industrial		304		312		(8	)	(2.6	%)
		578		568		10		1.8	%
Delivery only(c)
Small commercial & industrial		128		132		(4	)	(3.0	%)
Large commercial & industrial		204		216		(12	)	(5.6	%)
		332		348		(16	)	(4.6	%)
Total PPO and delivery only		910		916		(6	)	(0.7	%)
Total electric retail revenues		5,360		5,474		(114	)	(2.1	%)
Wholesale and miscellaneous revenue(d)		443		340		103		30.3	%
Total operating revenues	$	5,803	$	5,814	$	(11	)	(0.2	%)

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

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

(c) Delivery only revenues reflect revenue under tariff rates from customers electing to receive generation service from an alternative electric supplier, which includes a distribution charge and a CTC. Prior to ComEd’s full integration into PJM on May 1, 2004, ComEd’s transmission charges received from alternative electric suppliers were included in wholesale and miscellaneous revenue.

(d) Wholesale and miscellaneous revenues include transmission revenue (including revenue from PJM), sales to municipalities and other wholesale energy sales.

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Results of Operations—PECO

	2004			2003			Favorable (unfavorable) variance
Operating revenues	$	4,487		$	4,388		$	99
Operating expenses
Purchased power and fuel expense		2,172			2,096			(76	)
Operating and maintenance		547			576			29
Depreciation and amortization		518			487			(31	)
Taxes other than income		236			173			(63	)
Total operating expense		3,473			3,332			(141	)
Operating income		1,014			1,056			(42	)
Other income and deductions
Interest expense		(303	)		(324	)		21
Distributions on mandatorily redeemable preferred securities		—			(8	)		8
Equity in losses of unconsolidated affiliates		(25	)		—			(25	)
Other, net		18			2			16
Total other income and deductions		(310	)		(330	)		20
Income before income taxes		704			726			(22	)
Income taxes		249			253			4
Net income		455			473			(18	)
Preferred stock dividends		3			5			2
Net income on common stock	$	452		$	468		$	(16	)

Net Income. PECO’s net income in 2004 decreased primarily due to higher taxes other than income, due primarily to the reduction of real estate tax accruals in 2003, and higher depreciation and amortization expense due to increased CTC amortization, partially offset by higher operating revenues net of purchased power and fuel expense and lower operating and maintenance expense.

Operating Revenues. The changes in PECO’s operating revenues for 2004 compared to the 2003 consisted of the following:

	Electric			Gas			Total increase (decrease)
Volume	$	148		$	3		$	151
Rate changes and mix		1			111			112
Weather		(63	)		(21	)		(84	)
Customer choice		(78	)		—			(78	)
Retail revenue		8			93			101
PJM transmission		(15	)		—			(15	)
Other		3			10			13
Wholesale and miscellaneous revenues		(12	)		10			(2	)
Increase (decrease) in operating revenues	$	(4	)	$	103		$	99

Volume. PECO’s electric revenues increased as a result of higher delivery volume, exclusive of the effects of weather and customer choice, due to an increased number of customers and increased usage per customer, generally across all customer classes.

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Rate changes and mix. Electric revenues increased $1 million at PECO as a result of a $20 million increase related to a scheduled phase-out of merger-related rate reductions, offset by a $19 million decrease reflecting a change in rate mix due to changes in monthly usage patterns in all customer classes during 2004 as compared to 2003.

PECO’s gas revenues increased due to increases in rates through PUC-approved changes to the purchased gas adjustment clause that became effective March 1, 2003, June 1, 2003, December 1, 2003 and March 1, 2004. The average purchased gas cost rate per million cubic feet for 2004 was 33% higher than the rate in 2003. PECO’s purchased gas cost rates were reduced effective December 1, 2004.

Weather.The demand for electricity and gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and gas businesses, very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased sales of electricity and gas. Conversely, mild weather reduces demand. Revenues were negatively affected by unfavorable weather conditions at PECO in 2004 compared 2003. In the PECO service territory, cooling and heating degree-days were relatively unchanged and 5% lower, respectively, than the prior year.

Customer choice. For 2004 and 2003, 12% and 9%, respectively, of energy delivered to PECO’s retail customers was provided by an alternative electric supplier.

All PECO customers have the choice to purchase energy from an alternative electric supplier. This choice generally does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and generation service. Also, operating income is not affected by customer choice since any increase or decrease in revenues is completely offset by any related increase or decrease in purchased power expense.

	2004		2003
Retail customers purchasing energy from an alternative electric supplier:
Number of customers at period end	101,500		312,600
Percentage of total retail customers	7	%	20	%
Volume (GWhs)	4,605		3,135
Percentage of total retail deliveries	12	%	9	%

The increase in energy provided by alternative electric suppliers was due to the assignment of residential customers to alternative electric suppliers for a one-year term beginning in December 2003, as required by the PAPUC and PECO’s final electric restructuring order. The decrease in the number of customers served by alternative electric suppliers at year-end 2004 was due to these residential customers returning to PECO as their energy provider in December 2004.

Purchased Power and Fuel Expense.The changes in PECO’s purchased power and fuel expense for 2004 compared to 2003 consisted of the following:

	Electric			Gas			Total increase (decrease)
Volume	$	69		$	(2	)	$	67
PJM transmission		(15	)		—			(15	)
Prices		18			111			129
Customer choice		(78	)		—			(78	)
Weather		(27	)		(15	)		(42	)
Other		—			15			15
Increase (decrease) in purchased power and fuel expense	$	(33	)	$	109		$	76

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Volume.PECO’s purchased power and fuel expense increased due to increases, exclusive of the effects of weather and customer choice, in the number of customers and average usage per customer, generally across all customer classes.

Prices.PECO’s purchased power expense increased due to a change in the mix of average pricing related to PECO’s PPAs with Generation. Fuel expense for gas increased due to higher gas prices. See “Operating Revenues” above.

Customer choice.An increase in customer switching resulted in a reduction of purchased power expense, primarily due to PECO’s residential customers selecting or being assigned to purchase energy from an alternative electric supplier.

Weather.PECO’s purchased power and fuel expense decreased due to unfavorable weather conditions.

Other.PECO’s fuel expense increased primarily due to increased off-system sales of gas.

Operating and Maintenance Expense.The changes in operating and maintenance expense for the 2004 compared to 2003 consisted of the following:

	Increase (decrease)
Severance-related expenses	$	(17	)
Automated meter reading system implementation costs at PECO in 2003		(16	)
Storm costs(a)		(14	)
Payroll expense(b)		(11	)
Allowance for uncollectible accounts expense		(4	)
Corporate allocations(c)		34
Other		(1	)
Decrease in operating and maintenance expense	$	(29	)

(a) Storm costs were significantly higher in 2003 primarily as a result of Hurricane Isabel.

(b) PECO had fewer employees in 2004 compared to 2003.

(c) Higher corporate allocations primarily result from centralization of information technology, supply, human resources, communications, and finance functions into BSC from all of the Exelon operating companies, and changes in the corporate governance allocation calculation. Corporate governance allocations increased overall as a result of higher centralized costs distributed out of BSC, the sale of the Enterprises companies resulting in PECO comprising a greater base percentage of Exelon, and an SEC-mandated change to the methodology used to allocate Exelon’s corporate governance costs.

Depreciation and Amortization Expense.The changes in depreciation and amortization expense for 2004 compared to 2003 consisted of the following:

	Increase (decrease)
Competitive transition charge amortization	$	31
Depreciation expense		1
Other amortization expense		(1	)
Increase in depreciation and amortization expense	$	31

PECO’s additional amortization of the CTC is in accordance with PECO’s original settlement under the Pennsylvania Competition Act.

Taxes Other Than Income.The increase in taxes other than income in 2004 was primarily attributable to a $58 million reduction of real estate tax accruals during 2003 and $12 million related to

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the reversal of a use tax accrual in 2003 resulting from an audit settlement, partially offset by $4 million of lower payroll taxes in 2004.

Interest Expense and Distributions on Mandatorily Redeemable Preferred Securities.The aggregate of interest expense and distributions on mandatorily redeemable preferred securities decreased primarily due to lower outstanding debt and refinancings at lower rates, partially offset by a reversal in 2003 of accrued interest expense on Federal income taxes of $8 million to reflect actual interest paid. Effective December 31, 2003, with the adoption of FIN 46-R, PECO deconsolidated its financing trusts (see Note 1 of PECO’s Notes to Consolidated Financial Statements). PECO no longer records distributions on mandatorily redeemable preferred securities of subsidiaries but records interest expense to affiliates related to PECO’s obligations to the financing trusts.

Equity in Losses of Unconsolidated Affiliates.During 2004, PECO recorded $25 million of equity in net losses of subsidiaries as a result of deconsolidating its financing trusts.

Other, Net.The increase was primarily attributable to a reversal in 2003 of accrued interest on Federal income taxes of $14 million to reflect actual interest received and gains on disposition of assets in 2004.

Income Taxes. PECO’s effective income tax rate was 35.4% for 2004 compared to 34.8% for 2003. See Note 8 of PECO’s Notes to Consolidated Financial Statements for further details of the components of the effective income tax rates.

PECO Electric Operating Statistics and Revenue Detail

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

Retail Deliveries—(in GWhs)	2004	2003	Variance		% Change
Full service(a)
Residential	10,349	11,358	(1,009	)	(8.9	%)
Small commercial & industrial	6,728	6,624	104		1.6	%
Large commercial & industrial	14,908	14,739	169		1.1	%
Public authorities & electric railroads	914	897	17		1.9	%
Total full service	32,899	33,618	(719	)	(2.1	%)
Delivery only(b)
Residential	2,158	900	1,258		139.8	%
Small commercial & industrial	1,687	1,455	232		15.9	%
Large commercial & industrial	760	780	(20	)	(2.6	%)
Total delivery only	4,605	3,135	1,470		46.9	%
Total retail deliveries	37,504	36,753	751		2.0	%

(a) Full service reflects deliveries to customers taking electric service under tariffed rates.

(b) Delivery only service reflects customers receiving electric generation service from an alternative electric supplier.

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Electric Revenue	2004		2003		Variance			% Change
Full service(a)
Residential	$	1,317	$	1,444	$	(127	)	(8.8	%)
Small commercial & industrial		756		753		3		0.4	%
Large commercial & industrial		1,113		1,090		23		2.1	%
Public authorities & electric railroads		80		80		—		—
Total full service		3,266		3,367		(101	)	(3.0	%)
Delivery only(b)
Residential		164		65		99		152.3	%
Small commercial & industrial		86		75		11		14.7	%
Large commercial & industrial		20		21		(1	)	(4.8	%)
Total delivery only		270		161		109		67.7	%
Total electric retail revenues		3,536		3,528		8		0.2	%
Miscellaneous revenue(c)		203		215		(12	)	(5.6	%)
Total electric and other revenue	$	3,739	$	3,743	$	(4	)	(0.1	%)

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

(b) Delivery only revenue reflects revenue from customers receiving generation service from an alternative electric supplier, which includes a distribution charge and a CTC.

(c) Miscellaneous revenues include transmission revenue from PJM and other wholesale energy sales.

PECO Gas Sales Statistics and Revenue Detail

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

Deliveries to customers (in million cubic feet (mmcf))	2004		2003		Variance			% Change
Retail sales		59,949		61,858		(1,909	)	(3.1	%)
Transportation		27,148		26,404		744		2.8	%
Total		87,097		88,262		(1,165	)	(1.3	%)
Revenue	2004		2003		Variance			% Change
Retail sales	$	702	$	609	$	93		15.3	%
Transportation		18		18		—		—
Resales and other		28		18		10		55.6	%
Total gas revenue	$	748	$	645	$	103		16.0	%

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Results of Operations—Generation

	2004			2003			Favorable (unfavorable) variance
Operating revenues	$	7,703		$	8,586		$	(883	)
Operating expenses
Purchased power		2,307			3,620			1,313
Fuel		1,704			1,930			226
Operating and maintenance		2,201			1,874			(327	)
Impairment of Boston Generating, LLC long-lived assets		—			945			945
Depreciation and amortization		286			200			(86	)
Taxes other than income		166			120			(46	)
Total operating expenses		6,664			8,689			2,025
Operating income (loss)		1,039			(103	)		1,142
Other income and deductions
Interest expense		(103	)		(88	)		(15	)
Equity in earnings (losses) of unconsolidated affiliates		(14	)		49			(63	)
Other, net		130			(268	)		398
Total other income and deductions		13			(307	)		320
Income (loss) from continuing operations before income taxes and minority interest		1,052			(410	)		1,462
Income taxes		401			(176	)		(577	)
Income from continuing operations before minority interest		651			(234	)		885
Minority interest		6			(4	)		10
Income (loss) from continuing operations		657			(238	)		895
Discontinued operations
Loss from discontinued operations		(45	)		(35	)		(10	)
Income taxes		(29	)		(14	)		15
Loss from discontinued operations		(16	)		(21	)		5
Income (loss) before cumulative effect of changes in accounting principles		641			(259	)		900
Cumulative effect of changes in accounting principles		32			108			(76	)
Net income (loss)	$	673		$	(151	)	$	824

Net Income (Loss).Generation’s net income in 2004 increased from 2003 due to a number of factors. The increase in Generation’s 2004 net income was driven primarily by charges incurred in 2003 for the impairment of the long-lived assets of Boston Generating of $945 million (before income taxes) and the impairment and other transaction-related charges of $280 million (before income taxes) related to Generation’s investment in Sithe. Also, 2004 results were favorably affected by the acquisition of the remaining 50% of AmerGen and an increase in revenue, net of purchased power and fuel expense, primarily due to the decrease in average realized costs resulting from the increased success in the hedging program of fuel costs in 2004.

Cumulative effect of changes in accounting principles recorded in 2004 included a benefit of $32 million, net of income taxes, related to the adoption of FIN 46-R and in 2003 included income of $108 million, net of income taxes related to the of adoption of SFAS No. 143. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for further discussion of these effects.

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Operating Revenues. Operating revenues decreased in 2004 as compared to 2003, primarily as a result of the adoption of EITF 03-11.The adoption of EITF 03-11 resulted in a decrease in revenues of $980 million in 2004 as compared with the prior year. Generation’s sales in 2004 and 2003 were as follows:

Revenues (in millions)	2004		2003		Variance			% Change
Electric sales to affiliates	$	3,749	$	3,831	$	(82	)	(2.1%)
Wholesale and retail electric sales		3,227		4,107		(880	)	(21.4%)
Total energy sales revenues		6,976		7,938		(962	)	(12.1%)
Retail gas sales		448		414		34		8.2%
Trading portfolio		—		1		(1	)	(100.0%)
Other revenue(a)		279		233		46		19.7%
Total revenues	$	7,703	$	8,586	$	(883	)	(10.3%)
Sales (in GWhs)	2004		2003		Variance			% Change
Electric sales to affiliates		110,465		112,688		(2,223	)	(2.0%)
Wholesale and retail electric sales		92,134		112,816		(20,682	)	(18.3%)
Total sales		202,599		225,504		(22,905	)	(10.2%)

(a) Includes sales related to tolling agreements and fossil fuel sales.

Trading volumes of 24,001 GWhs and 32,584 GWhs for the years ended December 31, 2004 and 2003, respectively, are not included in the table above. The decrease in trading volume is a result of reduced volumetric and VAR trading limits in 2004, which are set by the Exelon Risk Management Committee and approved by the Board of Directors.

Electric Sales to Affiliates. Sales to ComEd and PECO declined $82 million in 2004 as compared to the prior year. The lower sales to ComEd and PECO were primarily driven by cooler than normal summer weather and lower average transfer prices in 2004 compared to the prior year.

Wholesale and Retail Electric Sales.The changes in Generation’s wholesale and retail electric sales for the year ended December 31, 2004 compared to the same period in 2003, consisted of the following:

Generation	Increase (decrease)
Effects of EITF 03-11 adoption (a)	$	(966	)
Sale of Boston Generating		(370	)
Addition of AmerGen operations		189
Other operations		267
Decrease in wholesale and retail electric sales	$	(880	)

(a) Does not include $14 million of EITF 03-11 reclassifications related to fuel sales that are included in other revenues.

The adoption of EITF 03-11 on January 1, 2004 resulted in the netting of certain revenues and the associated purchased power and fuel expense in 2004. The sale of Boston Generating in May 2004 resulted in less revenues from this entity in 2004 compared to the prior year. The acquisition of AmerGen resulted in increased market and retail electric sales of approximately $189 million in 2004.

The remaining increase in wholesale and retail electric sales was primarily due to higher volumes sold to the market at overall higher prices. The increase in market prices was primarily driven by higher coal prices in the Midwest region and higher oil and gas prices in the Mid-Atlantic region.

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Retail Gas Sales. Retail gas sales increased $34 million as a result of higher natural gas prices in 2004.

Other revenues.Other revenues include increased sales from tolling agreements, offset by a decrease in fossil fuel revenues.

Purchased Power and Fuel Expense.Generation’s supply of sales in 2004 and 2003, excluding the trading portfolio, was as follows:

Supply of Sales (in GWhs)	2004	2003	% Change
Nuclear generation(a)	136,621	117,502	16.3%
Purchases—non-trading portfolio(b)	48,968	83,692	(41.5%)
Fossil and hydroelectric generation(c, d)	17,010	24,310	(30.0%)
Total supply	202,599	225,504	(10.2%)

(a) Excludes AmerGen for 2003. AmerGen generated 20,135 GWhs during the year ended December 31, 2004.

(b) Sales in 2004 do not include 25,464 GWhs that were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11. Includes PPAs with AmerGen, which represented 12,667 GWhs in 2003.

(c) Fossil and hydroelectric supply mix changed as a result of decreased fossil fuel generation due to the sale of Boston Generating in May 2004.

(d) Excludes Sithe and Generation’s investment in TEG and TEP.

The changes in Generation’s purchased power and fuel expense for the year ended December 31, 2004 compared to the same period in 2003, consisted of the following:

Generation	Increase (decrease)
Effects of the adoption of EITF 03-11	$	(980	)
Addition of AmerGen operations		(344	)
Sale of Boston Generating		(290	)
Midwest Generation		(122	)
Price		(13	)
Mark-to-market adjustments on hedging activity		(14	)
Volume		267
Other		(43	)
Decrease in purchased power and fuel expense	$	(1,539	)

Adoption of EITF 03-11.The adoption of EITF 03-11 resulted in a decrease in purchased power and fuel expense of $980 million.

Addition of AmerGen Operations.As a result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003, purchased power decreased $379 million. In prior periods, Generation reported energy purchased from AmerGen as purchased power expense. The decrease in purchased power was partially offset by an increase of $35 million related to AmerGen’s nuclear fuel expense.

Sale of Boston Generating.The decrease in fuel and purchased power expense for Boston Generating is due primarily to the sale of the business in May 2004.

Midwest Generation.The volume of purchased power acquired from Midwest Generation declined in 2004 as a result of Generation exercising its option to reduce the capacity purchased from Midwest Generation, as announced in 2003.

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Price. The decrease reflects the forward hedging of fuel at lower costs than 2003 realized costs.

Hedging Activity.Mark-to-market losses on hedging activities at Generation were $2 million for the year ended December 31, 2004 compared to losses of $16 million for 2003. Hedging activities in 2004 relating to Boston Generating operations accounted for a gain of $4 million and hedging activities relating to other Generation operations in 2004 accounted for losses of $6 million.

Volume. Generation experienced increases in purchased power and fuel expense due to increased market and retail electric sales throughout its various sales regions.

Other. Other decreases in purchased power and fuel expense were primarily due to lower transmission expense resulting from reduced inter-region transmission charges, primarily associated with ComEd’s integration into PJM.

Generation’s average margins per megawatt hour (MWh) sold for the years ended December 31, 2004 and 2003 were as follows:

($/MWh)	2004		2003		% Change
Average electric revenue
Electric sales to affiliates	$	33.94	$	34.00	(0.2%)
Wholesale and retail electric sales		35.03		36.40	(3.8%)
Total—excluding the trading portfolio		34.43		35.20	(2.2%)
Average electric supply cost—excluding the trading portfolio(a)	$	17.60	$	24.61	(28.5%)
Average margin—excluding the trading portfolio		16.83		10.59	58.9%

(a) Average electric supply cost includes purchased power, and fuel costs associated with electric sales and PPAs with AmerGen in 2003. Average electric supply cost does not include purchased power and fuel cost associated with retail gas sales.

Impairment of the Long-Lived Assets of Boston Generating.In connection with the decision to transition out of the ownership of Boston Generating during the third quarter of 2003, Generation recorded a long-lived asset impairment charge of $945 million ($573 million net of income taxes). See Note 2 of Exelon’s Notes to Consolidated Financial Statements for further discussion of the sale of Generation’s ownership interest in Boston Generating.

Operating and Maintenance Expense.The changes in operating and maintenance expense for 2004 compared to 2003 consisted of the following:

Generation	Increase (decrease)
Addition of AmerGen operations	$	331
Decommissioning-related costs(a)		50
Refueling outage costs(b)		50
Pension, payroll and benefit costs, primarily associated with The Exelon Way		(84	)
DOE Settlement(c)		(52	)
Sale of Boston Generating		(12	)
Other		44
Increase in operating and maintenance expense	$	327

(a) Includes $40 million due to AmerGen asset retirement obligation accretion not included in 2003.

(b) Includes refueling outage cost of $43 million at AmerGen not included in 2003.

(c) See Note 13 of Exelon’s Notes to Consolidated Financial Statements for further discussion of the spent nuclear fuel storage settlement agreement with the DOE.

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The increase in operating and maintenance expense was primarily due to the inclusion of AmerGen in Generation’s consolidated results for 2004. Decommissioning-related costs increased primarily due to the inclusion of AmerGen in 2004 compared to the prior year. Accretion expense includes accretion of the asset retirement obligation and adjustments to offset the earnings impacts of certain decommissioning related activities revenues earned from ComEd and PECO, income taxes and depreciation of the ARC asset to zero. The increase in operating and maintenance expense was partially offset by reductions in payroll-related costs, the sale of Boston Generating in May 2004 and the settlement with the DOE to reimburse Generation for costs associated with storage of spent nuclear fuel.

Nuclear fleet operating data and purchased power costs data for the year ended December 31, 2004 and 2003 were as follows:

Generation	2004		2003
Nuclear fleet capacity factor(a)		93.5%		93.4%
Nuclear fleet production cost per MWh(a)	$	12.43	$	12.53
Average purchased power cost for wholesale operations per MWh(b)	$	47.11	$	43.25

(a) Includes AmerGen and excludes Salem, which is operated PSEG Nuclear.

(b) Includes PPAs with AmerGen in 2003.

The higher nuclear capacity factor and lower nuclear production costs were primarily due to ten fewer unplanned outages which offset the impact of one additional planned refuel outage. The lower production cost in 2004 as compared to 2003 was primarily due to the lower fuel costs and the impact of the spent fuel storage cost settlement agreement with the DOE which offset the added cost for one additional planned refuel outage and costs associated with the Dresden generator repairs during outages in the fourth quarter of 2004.

In 2004 as compared to 2003, the Quad Cities Units intermittently operated at pre-Extended Power Uprate (EPU) generation levels due to performance issues with their steam dryers.

Depreciation and Amortization. The increase in depreciation and amortization expense in 2004 as compared to 2003 was primarily due to the immediate expensing of an ARC, totaling $49 million, recorded in 2004 for which no useful life remains. The ARC was originally recorded in accordance with SFAS No. 143, which requires the establishment of an asset to offset the impact of an increased asset retirement obligation (ARO). See Note 14 of Exelon’s Notes to Consolidated Financial Statements for more information on the 2004 update to the ARO and ARC. The remaining increase is due to capital additions and the consolidation of AmerGen. These increase were partially offset by a decrease in depreciation expense related to the Boston Generating facilities, which were sold in May 2004.

Effective Income Tax Rate.The effective income tax rate from continuing operations was 38% for 2004 compared to 43% for 2003. The decrease in the effective rate was primarily attributable to income taxes associated with nuclear decommissioning trust activity, income tax deductions related to non-taxable employee benefits and the dilution of the permanent income tax benefits due to the increase in pre-tax income in 2004. See Note 12 of Generation’s Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

Discontinued Operations.In 2004, the loss from discontinued operations included Sithe’s results from April 1, 2004 through the end of the year and the results from AllEnergy, a former subsidiary of Exelon Energy. Generation had accounted for the investment in Sithe as an unconsolidated equity method investment prior to its consolidation on March 31, 2004 pursuant to FIN 46-R. The loss from discontinued operations in 2003 included the results of AllEnergy. Sithe’s net impact to Generation was a loss of $19 million in 2004, while AllEnergy produced $3 million of net income in 2004. In 2003, AllEnergy had a net loss of $21 million. See Note 2 of Exelon’s Notes to Consolidated Financial Statements for further information.

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Liquidity and Capital Resources

Exelon’s businesses are capital intensive and require considerable capital resources. These capital resources are primarily provided by internally generated cash flows from operations. When necessary, Exelon obtains funds from external sources in the capital markets and through bank borrowings. Exelon’s access to external financing on reasonable terms depends on Exelon and its subsidiaries’ credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to the extent that Exelon no longer has access to the capital markets at reasonable terms, Exelon has access to revolving credit facilities with aggregate bank commitments of $1.5 billion that it currently utilizes to support its commercial paper programs. See the “Credit Matters” section of “Liquidity and Capital Resources” for further discussion.

Exelon primarily uses its capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay common stock dividends, fund its pension obligations and invest in new and existing ventures. Exelon spends a significant amount of cash on construction projects that have a long-term return on investment. Additionally, ComEd and PECO operate in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time. As a result of these factors, Exelon has historically operated with a working capital deficit. However, Exelon expects operating cash flows to be sufficient to meet operating and capital expenditure requirements. Future acquisitions that Exelon may undertake, other than the proposed merger with PSEG which will require the issuance of Exelon common stock in exchange for PSEG common stock, may involve external debt financing or the issuance of additional Exelon common stock.

Cash Flows from Operating Activities

ComEd’s and PECO’s cash flows from operating activities primarily result from sales of electricity and gas to a stable and diverse base of retail customers at fixed prices and are weighted toward the third quarter of each fiscal year. ComEd’s and PECO’s future cash flows will be affected by the economy, weather, customer choice and future regulatory proceedings on their revenues and their ability to achieve operating cost reductions. See Note 4 of Exelon’s Notes to Consolidated Financial Statements for further discussion of regulatory proceedings. Generation’s cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including ComEd and PECO. Generation’s future cash flows from operating activities will be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs.

Cash flows from operations have been a reliable, steady source of cash flow, sufficient to meet operating and capital expenditures requirements. Taking into account the factors noted above, Exelon also obtains cash from non-operating sources such as the proceeds from the debt issuance in 2005 to fund Exelon’s $2 billion pension contribution (see Note 10 of Exelon’s Notes to Consolidated Financial Statements). Operating cash flows after 2006 could be negatively affected by changes in the rate regulatory environments of ComEd and PECO, although any effects are not expected to hinder the ability of PECO to fund its business requirements. Under Illinois law enacted in 1997, ComEd is required, beginning in 2007, to purchase energy in the wholesale energy markets in order to meet the retail energy needs of ComEd’s customers because ComEd does not own any generation. If the price at which ComEd is allowed to sell energy beginning in 2007 is below ComEd’s cost to procure and deliver electricity, there may be potential material adverse consequences to ComEd and, possibly, Exelon. On January 24, 2006, the ICC, by a unanimous vote, approved a reverse-auction competitive bidding process for procurement of power by ComEd for the time period after 2006. The procurement process is similar to the process described in the Procurement Case with some modifications to enhance consumer protection. The auction will be administered by an independent auction manager, with oversight by the ICC staff. The first auction is scheduled to take place during the fall of 2006, at which time ComEd’s entire load will be up for bid. To mitigate the effects of changes in future prices,

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the load will be staggered in three-year contracts. To further mitigate the impact on its residential customers of transitioning to this process, ComEd has offered to develop a “cap and deferral” proposal to ease the impact of the expected increase in rates on residential customers, some or all of which could require regulatory or legislative approval to implement. A cap and deferral proposal, generally speaking, would limit the procurement costs that ComEd could pass through to its customers for a specified period of time and allow ComEd to collect any unrecovered procurement costs in later years.

Additionally, Exelon, through ComEd, has taken certain tax positions, which have been disclosed to the IRS, to defer the tax gain on the 1999 sale of its fossil generating assets. As discussed in Note 12 of Exelon’s Notes to the Consolidated Financial Statements, this tax obligation is significant.

The following table provides a summary of the major items affecting Exelon’s cash flows from operations:

	2005			2004			Variance
Net income	$	923		$	1,864		$	(941	)
Add (subtract):
Non-cash operating activities(a)		3,910			2,274			1,636
Income taxes		138			293			(155	)
Changes in working capital and other noncurrent assets and liabilities(b)		(821	)		237			(1,058	)
Pension contributions and postretirement healthcare benefit payments, net		(2,003	)		(270	)		(1,733	)
Net cash flows provided by operations	$	2,147		$	4,398		$	(2,251	)

(a) Represents depreciation, amortization and accretion, deferred income taxes, cumulative effect of a change in accounting principle, impairment of goodwill, investments and long-lived assets, and other non-cash charges.

(b) Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt.

The reduction of cash flows from operations during the current year is primarily the result of $2 billion of discretionary contributions to Exelon’s pension plans during the first quarter of 2005, which was initially funded through a term loan agreement, as further described in the “Cash Flows from Financing Activities” section below. Of the total contribution, ComEd, PECO and Generation contributed $803 million, $109 million and $844 million, respectively. ComEd’s and PECO’s contributions were funded by capital contributions from Exelon. The Generation contribution was primarily funded by capital contributions from Exelon and included $2 million from internally generated funds. Exelon did not contribute to its pension plans in subsequent quarters of 2005. Discretionary tax-deductible pension plan payments were $439 million in 2004. Exelon also contributed $11 million during 2004 to the pension plans needed to satisfy minimum funding requirements of the Employee Retirement Income Security Act.

Cash flows provided by operations for 2005 and 2004 by registrant were as follows:

	2005		2004
Exelon	$	2,147	$	4,398
ComEd		247		1,330
PECO		704		983
Generation		972		1,947

Excluding the March 2005 discretionary pension contributions discussed above, changes in Exelon’s, ComEd’s, PECO’s and Generation’s cash flows from operations were generally consistent with changes in its results of operations, as adjusted by changes in working capital in the normal course of business.

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In addition to the items mentioned in “Results of Operations” and the discretionary pension contributions discussed above, significant operating cash flow impacts for ComEd and Generation for 2005 and 2004 were as follows:

ComEd

• In the third quarter of 2005, ComEd settled $325 million of interest rate swaps that were designated as cash flow hedges for a loss of $15 million which was paid in October 2005. This was recorded as a pre-tax charge to net income because the underlying transaction for which these interest rate swaps were entered into is no longer probable of occurring.

• During 2004, ComEd paid $86 million for prepayment premiums on the retirement of debt.

Generation

• During 2005, Generation had net disbursements of counterparty collateral of $187 million compared to $73 million of net collections of counterparty collateral in 2004. The increase in cash outflows from 2004 was primarily due to changes in collateral requirements resulting from increased activity within exchange-based markets for energy and fossil fuel.

• During 2005, Generation had net payments of approximately $165 million primarily due to increased use of financial instruments to hedge future sales of power and future purchases of fossil fuel.

• During 2005, Exelon received a $102 million Federal income tax refund for capital losses generated in 2003 related to Generation’s investment in Sithe, which were carried back to prior periods.

• In December 2004, TXU and Generation terminated a tolling agreement and entered into a new agreement. Upon termination of the original agreement, Generation received a cash payment of $172 million. The resulting gain was deferred and will be recognized as income over the contractual term of the new agreement.

Cash Flows from Investing Activities

Cash flows provided by (used in) investing activities for 2005 and 2004 by registrant were as follows:

	2005			2004
Exelon	$	(2,487	)	$	(1,739	)
ComEd		(479	)		486
PECO		(241	)		(251	)
Generation		(1,294	)		(1,103	)

Capital expenditures by registrant and business segment for 2005 and projected amounts for 2006 are as follows:

	2005		2006
ComEd	$	776	$	925
PECO		298		333
Generation		1,067		1,115
Other(a)		24		68
Total Exelon capital expenditures	$	2,165	$	2,441

(a) Other primarily consists of corporate operations.

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Projected capital expenditures and other investments for Exelon, ComEd, PECO and Generation are subject to periodic review and revision to reflect changes in economic conditions and other factors.

ComEd and PECO. Approximately 50% of the projected 2006 capital expenditures at ComEd and PECO are for continuing projects to maintain and improve the reliability of their transmission and distribution systems. The remaining amount is for capital additions to support new business and customer growth. Exelon is continuing to evaluate its total capital spending requirements. Exelon anticipates that ComEd’s and PECO’s capital expenditures will be funded by internally generated funds, borrowings and the issuance of debt or preferred securities or capital contributions from Exelon.

Generation. Generation’s capital expenditures for 2005 reflect additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages) and nuclear fuel. Exelon anticipates that Generation’s capital expenditures will be funded by internally generated funds, borrowings or capital contributions from Exelon.

Other significant investing activities for Exelon, ComEd, PECO and Generation for 2005 and 2004 were as follows:

Exelon

• Exelon contributed $102 million and $56 million to its investments in synthetic fuel-producing facilities during 2005 and 2004, respectively.

• Exelon received cash proceeds of $76 million, net of $2 million held in escrow at December 31, 2004, from the sale of its investments in affordable housing in 2004.

• Cash proceeds of $227 million, net of transaction costs and contingency payments on prior year dispositions, were received during 2004 from the sales of Exelon Thermal Holdings, Inc., substantially all of the operating businesses of Services, and Enterprises’ investments in PECO TelCove and other equity method and cost basis investments of Enterprises.

• Early settlement on an acquisition note receivable from the 2003 disposition of InfraSource resulted in cash proceeds of $30 million during 2004.

ComEd

• As a result of its prior contributions to the Exelon intercompany money pool, $308 million and $97 million were returned to ComEd during 2005 and 2004, respectively.

PECO

• During 2005, $26 million was returned to PECO as a result of its prior contributions to the Exelon intercompany money pool and during 2004, $34 million was contributed by PECO.

Generation

• During 2005, Generation received approximately $52 million from Generation’s nuclear decommissioning trust funds for reimbursement of expenditures previously incurred for nuclear plant decommissioning activities related to the retired units.

• On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. Specifically, subsidiaries of Generation closed on the acquisition of Reservoir Capital Group’s 50% interest in Sithe for cash payments of $97 million and the sale of 100% of Sithe to Dynegy, for net cash proceeds of $103 million. See Note 3 of Exelon’s Notes to Consolidated Financial Statements for further discussion of the sale of Sithe.

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• On March 31, 2004, Generation consolidated the assets and liabilities of Sithe under the provisions of FIN 46-R, which resulted in an increase in cash of $19 million. See Notes 1 and Note 3 of Exelon’s Notes to Consolidated Financial Statements for further information regarding the FIN 46-R consolidation of Sithe.

• Generation received cash proceeds of $42 million from the January 2004 sale of three gas turbines.

• During 2004, Generation used $29 million of restricted cash related to Sithe’s operating activities and used $11 million of restricted cash to support the operations of Boston Generating and provided $4 million for certain environmental obligations.

Cash Flows from Financing Activities

Cash flows provided by (used in) financing activities for 2005 and 2004 by registrant were as follows:

	2005			2004
Exelon	$	(19	)	$	(2,627	)
ComEd		240			(1,820	)
PECO		(500	)		(676	)
Generation		93			(739	)

On March 7, 2005, Exelon entered into a $2 billion term loan agreement. The loan proceeds were used to fund discretionary contributions of $2 billion to Exelon’s pension plans, including contributions of $803 million, $109 million and $842 million by ComEd, PECO and Generation, respectively. To facilitate the contributions by ComEd, PECO and Generation, Exelon contributed the corresponding amounts to the capital of each company. On April 1, 2005, Exelon entered into a $500 million term loan agreement that was subsequently fully borrowed to reduce this $2 billion term loan. During the second quarter of 2005, $200 million of this $500 million term loan, as well as the remaining $1.5 billion balance on the $2 billion term loan described above, were repaid with the net proceeds received from the issuance of the long-term senior notes discussed below. The $300 million outstanding balance under the term loan agreement bears interest at a variable rate determined, at Exelon’s option, by either the Base Rate or the Eurodollar Rate (as defined in the term loan agreement). On November 30, 2005, the term loan was amended and restated to extend the agreement from December 1, 2005 to September 16, 2006. See Note 10 of Exelon’s Notes to Consolidated Financial Statements for further discussion.

On June 9, 2005, Exelon issued and sold $1.7 billion of senior debt securities pursuant to its senior debt indenture, dated as of May 1, 2001, consisting of $400 million of 4.45% senior notes due 2010, $800 million of 4.90% senior notes due 2015 and $500 million of 5.625% senior notes due 2035. The net proceeds from the sale of the notes were used to repay the $1.5 billion in remaining principal due on the $2 billion term loan agreement and $200 million of the $500 million term loan agreement referenced above. Exelon may redeem some or all of the notes at any time prior to maturity at a specified redemption price. The notes are unsecured and rank equally with the other senior unsecured indebtedness of Exelon. Additionally, Exelon settled interest rate swaps for a net payment of $38 million and paid approximately $12 million of fees in connection with the debt offering.

In 2005, ComEd used funding received from $324 million of commercial paper to retire long-term debt.

In 2004, ComEd retired $1.2 billion of long-term debt, including $1.0 billion prior to its maturity and $206 million at maturity in accordance with an accelerated liability management plan and retired $728 million of long-term debt due to financing affiliates. Additionally, in 2004, Generation paid $27 million of

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a note payable to Sithe. During 2004, Exelon also issued $164 million of commercial paper, net of payments, and received cash proceeds of $33 million from the settlement of interest-rate swaps.

From time to time and as market conditions warrant, Exelon, ComEd, PECO and Generation may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to strengthen their respective balance sheets.

Cash dividend payments and distributions in 2005 and 2004 by registrant were as follows:

	2005			2004
Exelon	$	(1,070	)	$	(831	)
ComEd		(498	)		(457	)
PECO		(473	)		(394	)
Generation		(857	)		(662	)

On January 24, 2006, Exelon’s board of directors declared a quarterly dividend of $0.40 per share on Exelon’s common stock. The dividend is payable on March 10, 2006 to shareholders of record at the end of the day on February 15, 2006. The dividend is payable on June 10, 2006, to shareholders of record at the end of the day on May 15, 2006, provided the Merger with PSEG with has not closed. See ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities for additional information.

The declaration and payment of dividends by ComEd is a matter for determination by the board of directors of ComEd. The ComEd board of directors, at a meeting held in December 2005, determined that the board would consider the dividend policy of ComEd at a subsequent meeting. The ComEd board has not discussed dividend policy in depth or taken action to establish or revise ComEd’s dividend policy. If and to the extent that future dividends from ComEd are less than the level of dividends determined in accordance with past practices at ComEd, Exelon expects that distributions from Generation would be increased.

Exelon received proceeds from employee stock plans of $222 million and $240 million during 2005 and 2004, respectively.

Additionally, Exelon purchased treasury shares totaling $362 million and $82 million during 2005 and 2004, respectively.

Intercompany Money Pool.ComEd’s net borrowings from the Exelon intercompany money pool increased $140 million during 2005. Generation’s net borrowings from the Exelon intercompany money pool decreased $191 million and $162 million during 2005 and 2004, respectively.

Credit Issues

Exelon Credit Facilities

Exelon meets its short-term liquidity requirements primarily through the issuance of commercial paper by Exelon, ComEd, PECO and Generation. At December 31, 2005, Exelon, along with ComEd, PECO and Generation, participated with a group of banks in a $1 billion unsecured revolving facility maturing on July 16, 2009 and a $500 million unsecured revolving credit facility maturing on October 31, 2006. 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.

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At December 31, 2005, Exelon, ComEd, PECO and Generation had the following sublimits and available capacity under the credit agreements and the indicated amounts of outstanding commercial paper:

Borrower	Bank Sublimit (a)		Available Capacity (b)		Outstanding Commercial Paper
Exelon	$	100	$	100	$	—
ComEd		650		623		459
PECO		350		350		220
Generation		400		353		311

(a) Sublimits under the credit agreements can change upon written notification to the bank group.

(b) Available capacity represents the bank sublimit net of outstanding letters of credit. The amount of commercial paper outstanding does not reduce the available capacity under the credit facilities.

Interest rates on advances under the credit facilities are based on either prime or the London Interbank Offering Rate (LIBOR) 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 LIBOR adder is 170 basis points.

The average interest rates on commercial paper in 2005 for Exelon, ComEd, PECO and Generation were approximately 3.28%, 4.13%, 3.44% and 4.12%, respectively.

The credit agreements require Exelon, ComEd, PECO and Generation to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and, in the case of Exelon and Generation, revenues from Sithe and interest on the debt of its project subsidiaries. The following table summarizes the minimum thresholds reflected in the credit agreements for the twelve-month period ended December 31, 2005:

	Exelon	ComEd	PECO	Generation
Credit agreement threshold	2.65 to 1	2.25 to 1	2.25 to 1	3.25 to 1

At December 31, 2005, Exelon, ComEd, PECO and Generation were in compliance with the foregoing thresholds.

On February 10 through 13, 2006, Generation entered into separate additional credit facilities with aggregate bank commitments of $875 million, which may be drawn down in the form of loans and/or letters of credit. The additional credit facilities are for a term of 364 days and contain the same terms as the revolving credit facilities described above. The credit facilities will be used primarily to meet short-term funding requirements and to issue letters of credit.

Capital Structure. At December 31, 2005, the capital structures of Exelon, ComEd, PECO and Generation consisted of the following:

	Exelon Consolidated		ComEd		PECO (a)		Generation
Long-term debt	35	%	25	%	19	%	29	%
Long-term debt to affiliates(b)	20		12		50		—
Common equity	39		57		26		—
Member’s equity	—		—		—		64
Preferred securities	—		—		1		—
Notes payable	6		6		4		7
Minority interest	—		—		—		—

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(a) As of December 31, 2005, PECO’s capital structure, excluding the deduction from shareholders’ equity of the $1.2 billion receivable from Exelon (which amount is deducted for GAAP purposes as reflected in the table, but is excluded from the percentages in this footnote), consisted of 38% common equity, 1% preferred securities, 3% notes payable and 58% long-term debt, including long-term debt to unconsolidated affiliates.

(b) Includes $4.5 billion, $1.3 billion and $3.2 billion owed to unconsolidated affiliates of Exelon, ComEd and PECO, respectively, that qualify as special purpose entities under FIN 46-R. These special purpose entities were created for the sole purpose of issuing debt obligations to securitize intangible transition property and CTCs of ComEd and PECO or mandatorily redeemable preferred securities. See Note 1 of Exelon’s Notes to Consolidated Financial Statements for further information regarding FIN 46-R.

Intercompany Money Pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, Exelon operates an intercompany money pool. Participation in the money pool is subject to authorization by the corporate treasurer. ComEd, PECO, Generation and BSC may participate in the money pool as lenders and borrowers, and Exelon and UII, LLC, a wholly owned subsidiary of Exelon, may participate as lenders. 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. Maximum amounts contributed to and borrowed from the money pool by participant during 2005 are described in the following table in addition to the net contribution or borrowing as of December 31, 2005:

	Maximum Contributed		Maximum Borrowed		December 31, 2005 Contributed (Borrowed)
ComEd	$	517	$	200	$	(140	)
PECO		210		20		8
Generation		54		540		(92	)
BSC		30		156		(16	)
UII, LLC		3		—		—
Exelon		242		—		241

Sithe Long-Term Debt

Debt totaling approximately $820 million was eliminated from the Consolidated Balance Sheets of Exelon and Generation as a result of the sale of Sithe on January 31, 2005. See Note 3 of Exelon’s Notes to Consolidated Financial Statements for further discussion regarding the sale of Sithe.

Security Ratings

Exelon’s, ComEd’s, PECO’s and Generation’s access to the capital markets, including the commercial paper market, and their respective financing costs in those markets depend on the securities ratings of the entity that is accessing the capital markets. The following table shows the Registrants’ securities ratings at December 31, 2005:

	Securities	Moody’s Investors Service		Standard & Poor’s Corporation	Fitch Ratings.
Exelon	Senior unsecured debt	Baa2		BBB	BBB+
	Commercial paper	P2		A2	F2
ComEd	Senior secured debt	Baa1	(a)	A-	A-
	Commercial paper	P2		A2	F2
	Transition bonds(b)	Aaa		AAA	AAA
PECO	Senior secured debt	A2		A-	A
	Commercial paper	P1		A2	F1
	Transition bonds(c)	Aaa		AAA	AAA
Generation	Senior unsecured debt	Baa1		BBB+	BBB+
	Commercial paper	P2		A2	F2

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(a) Downgraded by Moody’s Investor Service from A3 to Baa1 on December 15, 2005.

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

(c) Issued by PETT, an unconsolidated affiliate of PECO.

On September 30, 2005, Moody’s Investors Service placed ComEd’s ratings under review for a possible downgrade due to the adverse regulatory environment in Illinois as described in Note 4 of Exelon’s Notes to Consolidated Financial Statements. On December 15, 2005, Moody’s Investor Service downgraded the long-term debt and preferred stock ratings of ComEd. ComEd’s short-term rating for commercial paper was not downgraded. All of ComEd’s ratings remain on review for possible downgrade. The ratings outlook for Exelon, Generation and PECO were unchanged. On October 3, 2005, Standard & Poor’s Rating Services (S&P) lowered its corporate credit ratings and senior unsecured debt ratings on Exelon and its subsidiaries due to the adverse regulatory environment in Illinois as described in Note 4 of Exelon’s Notes to Consolidated Financial Statements. The short-term debt ratings and senior secured ratings were unaffected. The ratings on all Exelon affiliates remain on CreditWatch with negative implications pending the completion of the merger with PSEG. On January 9, 2006, Fitch Ratings revised the rating outlook on the long-term debt and preferred stock of ComEd to negative from stable. The rating outlooks on all other Exelon affiliates remain stable. None of Exelon’s borrowings is subject to default or prepayment as a result of a downgrading of securities although such a downgrading could increase fees and interest charges under Exelon’s credit facilities.

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 its 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 contracts law, if Exelon or 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 its 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 Exelon or Generation’s situation at the time of the demand. If Exelon 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.

Shelf Registrations

As of December 31, 2005, Exelon, ComEd and PECO had current shelf registration statements for the sale of $300 million, $555 million and $550 million, respectively, of securities that were effective with the SEC. The ability of Exelon, ComEd or PECO to sell securities off its shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, the current financial condition of the company, its securities ratings and market conditions.

Regulatory Restrictions

The issuance of long-term debt or equity securities by ComEd requires the prior authorization of the ICC. The issuance by PECO of long-term debt or equity securities requires the prior authorization of the PAPUC. ComEd and PECO normally obtain the required approvals on a periodic basis to cover their financing needs or in connection with a specific financing.

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Under PUHCA, the SEC had financing jurisdiction over ComEd’s and PECO’s short-term financings and all of Generation’s and Exelon’s financings. As a result of the repeal of PUHCA, effective February 8, 2006, the SEC’s financing jurisdiction under PUHCA for ComEd’s and PECO’s short-term financings and Generations financings reverted to FERC and Exelon’s financings are no longer subject to regulatory approvals.

On February 7, 2006, FERC issued a blanket authorization for the acquisition of securities pursuant to the Exelon Utility Money Pool Agreement, subject to the same limits and reporting requirements imposed by the SEC under PUHCA. The FERC order is effective for one year instead of the usual two-year effective period. The one-year period will allow Exelon to maintain the status quo while FERC determines whether on rehearing to amend its rules to make future applications unnecessary (e.g., blanket authorizations for all money pool transactions). Because PSE&G was not an applicant requesting participation in the Exelon Utility Money Pool, the FERC denied Exelon’s request to allow PSE&G to participate in the Exelon Utility Money Pool post-merger.

On December 7, 2005, ComEd and PECO filed applications for short-term financing authority with the FERC in the amounts of $2.5 billion and $1.5 billion, respectively. In February 2006, ComEd and PECO received orders from the FERC approving their requests, effective February 8, 2006 through December 31, 2007.

Generation currently has blanket financing authority that it received from FERC in November 2000 that became effective again with the repeal of PUHCA. If the FERC proceeding relating to Generation’s market-based rate authority results in revocation of that authority, Generation’s blanket financing authority may also be revoked. If that financing authority is revoked, it is possible that the revocation of financing authority would be effective prospectively. It is also possible that the revocation of financing authority might be retroactive to October 2, 2005. FERC has adopted regulations that would grandfather prior SEC approvals of financings at a company’s election. The FERC regulations require that companies intending to issue securities in reliance on their SEC financing orders file with FERC a copy of their SEC financing order within 30 days after the effective date of PUHCA repeal. In light of the potential uncertainty relating to the possible revocation of FERC’s blanket financing authority, Exelon has filed its SEC financing order with the FERC. The SEC financing order contains certain terms, limits, and reporting requirements which Exelon continues to review to determine the extent to which it would be subject to such conditions.

Under applicable law, ComEd, PECO and Generation can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at ComEd, PECO or Generation may limit the dividends that these companies can distribute to Exelon. At December 31, 2005, Exelon had retained earnings of $3.2 billion, including ComEd’s retained deficit of $(81) million consisting of $1,099 million of retained earnings appropriated for future dividends offset by an unappropriated retained deficit of ($1,180) million, PECO’s retained earnings of $649 million and Generation’s undistributed earnings of $1,002 million.

Investments in Synthetic Fuel-Producing Facilities

Exelon, through three wholly owned subsidiaries, has investments in synthetic fuel-producing facilities. Section 45k (formerly Section 29) of the Internal Revenue Code provides tax credits for the sale of synthetic fuel produced from coal. However, Section 45k contains a provision under which credits are phased out (i.e., eliminated) in the event crude oil prices for a year exceed certain thresholds.

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The following table (in dollars) provides the estimated phase-out range for 2006 and 2007 based on the per barrel price of oil. The table also contains the annual average New York Mercantile Exchange, Inc. index (NYMEX) future prices per barrel at December 31, 2005 for 2006 and 2007.

	Estimated 2006		Estimated 2007
Beginning of Phase-Out Range(a)	$	59	$	61
End of Phase-Out Range(a)		75		76
Annual Average NYMEX Future Price		65		66

(a) Estimated phase-out ranges are calculated using inflation rates published by the IRS after year-end. The inflation rate used by Exelon to estimate the 2006 and 2007 phase-out ranges was 2%.

Based on the 2006 and 2007 NYMEX futures prices at December 31, 2005, Exelon estimates there will be a phase-out of tax credits of 38% and 36% in 2006 and 2007, respectively. This would decrease Exelon’s net income as compared to 2005 by as much as $38 million and $36 million in 2006 and 2007, respectively. These estimates can change significantly due to the volatility in oil prices.

The purchase price for Exelon’s investments in synthetic fuel-producing facilities is comprised of fixed and variable components. The fixed component is in the form of a non-recourse note that requires nonrefundable quarterly payments of principal and interest to sellers. The variable component is based on the value of the estimated tax credits that will be allocated to Exelon. Exelon’s subsidiaries are also required to make capital contributions based on the allocated amount of tax credits to the operators to fund the operating losses.

Given the refundable nature of the variable components of the purchase price and operating losses paid to the sellers and operators of the facilities, respectively, Exelon’s results of operations and cash flows are not anticipated to be affected by a phase-out of tax credits due to a rise in crude oil prices to the extent of these variable components (notwithstanding the differences in the timing of refundable variable payments and the associated refunds). However, Exelon’s results of operations and cash flows could be negatively affected to the extent that Exelon is not allocated enough tax credits to cover the principal and interest payments due on the non-recourse notes representing the non-refundable fixed component of the purchase price.

Absent any efforts to mitigate market price exposure, a phase-out could result in the reduction of the non-operating net income generated by the investments and could result in an estimated after-tax non-operating loss of up to $70 million per year in the event all tax credits are completely eliminated, exclusive of any impacts related to the intangible assets. In 2005, Exelon and Generation entered into certain derivatives in the normal course of trading operations to economically hedge a portion of this exposure. These derivatives could result in after-tax cash proceeds to Exelon of up to $42 million and $42 million in 2006 and 2007, respectively, in the event the tax credits are completely phased out. See Note 12 of Exelon’s Notes to the Consolidated Financial Statements for further information regarding Exelon’s investments in synthetic fuel-producing facilities.

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Contractual Obligations and Off-Balance Sheet Arrangements

Exelon

The following table summarizes Exelon’s future estimated cash payments under existing contractual obligations, including payments due by period.

	Total		Payment due within						Due 2011 and beyond
			2006		2007-2008		2009-2010
Long-term debt	$	8,140	$	405	$	1,125	$	669	$	5,941
Long-term debt to financing trusts		4,508		507		1,950		1,506		545
Interest payments on long-term debt(a)		4,199		697		767		691		2,044
Interest payments on long-term debt to financing trusts(a)		1,588		267		399		173		749
Capital leases		46		2		4		4		36
Operating leases		766		55		108		92		511
Purchase power obligations		8,800		2,124		1,672		1,258		3,746
Fuel purchase agreements		4,299		754		1,235		933		1,377
Other purchase obligations(b)		987		211		283		275		218
Chicago agreement(c)		42		6		12		12		12
Regulatory commitments		10		10		—		—		—
Spent nuclear fuel obligation		906		—		—		—		906
Obligation to minority shareholders		46		3		5		5		33
Pension ERISA minimum funding requirement		11		11		—		—		—
Asset retirement obligations(d)		4,157		66		13		12		4,066
Total contractual obligations	$	38,505	$	5,118	$	7,573	$	5,630	$	20,184

(a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2005 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2005. The contributions will be funded in part by additional debt anticipated to be issued in 2005. Estimated future payments associated with the anticipated debt issuance have not been included in the table above.

(b) Commitments for services, materials and information technology.

(c) 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.

(d) Represents the present value of Generation’s obligation to decommission nuclear plants and ComEd’s, PECO’s and Generation’s conditional AROs recorded in connection with the adoption of FIN 47. AROs associated with assets that have been fully depreciated but which are still in service have been reflected as payments due in 2006.

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ComEd

The following table summarizes ComEd’s future estimated cash payments under existing contractual obligations, including payments due by period.

			Payment due within						Due 2011 and beyond
	Total		2006		2007-2008		2009-2010
Long-term debt	$	2,839	$	328	$	564	$	230	$	1,717
Long-term debt to financing trusts		1,348		307		680		—		361
Interest payments on long-term debt(a)		1,488		420		238		207		623
Interest payments on long-term debt to financing trusts(a)		731		75		95		52		509
Operating leases		153		16		37		30		70
Other purchase commitments(b)		22		14		8		—		—
Chicago agreement(c)		42		6		12		12		12
Regulatory commitments		10		10		—		—		—
Asset retirement obligations(d)		151		62		12		11		66
Total contractual obligations	$	6,784	$	1,238	$	1,646	$	542	$	3,358

(a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2005 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b) Commitments for services, materials and information technology.

(c) 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.

(d) Represents conditional AROs recorded in connection with the adoption of FIN 47. AROs associated with assets that have been fully depreciated but which are still in service have been reflected as payments due in 2006.

PECO

The following table summarizes PECO’s future estimated cash payments under existing contractual obligations, including payments due by period.

	Total		Payment due within						Due 2011 and beyond
(in millions)			2006		2007-2008		2009-2010
Long-term debt	$	1,184	$	—	$	450	$	30	$	704
Long-term debt to financing trusts		3,159		199		1,270		1,506		184
Interest payments on long-term debt(a)		361		52		93		72		144
Interest payments on long-term debt to financing trusts(a)		857		192		304		121		240
Operating leases		8		3		2		2		1
Other purchase commitments(b)		220		37		46		46		91
Asset retirement obligations(c)		20		4		1		1		14
Total contractual obligations	$	5,809	$	487	$	2,166	$	1,778	$	1,378

(a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2005 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b) Commitments for services, materials and information technology.

(c) Represents conditional AROs recorded in connection with the adoption of FIN 47. AROs associated with assets that have been fully depreciated but which are still in service have been reflected as payments due in 2006.

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Generation

The following table summarizes Generation’s future estimated cash payments under existing contractual obligations, including payments due by period.

	Total		Payment Due within						Due 2011 and beyond
(in millions)			2006		2007-2008		2009-2010
Long-term debt	$	1,805	$	12	$	24	$	13	$	1,756
Intercompany money pool		92		92		—		—		—
Interest obligations related to long-term debt (a)		854		94		185		184		391
Capital leases		46		2		4		4		36
Operating leases		534		31		59		53		391
Purchase power obligations		8,800		2,124		1,672		1,258		3,746
Fuel purchase agreements		4,299		754		1,235		933		1,377
Other purchase commitments(b)		688		112		219		230		127
Obligation to minority shareholders		46		3		5		5		33
Pension ERISA minimum funding requirement		11		11		—		—		—
Spent nuclear fuel obligations		906		—		—		—		906
Asset retirement obligations(c)		3,986		—		—		—		3,986
Total contractual obligations	$	22,067	$	3,235	$	3,403	$	2,680	$	12,749

(a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2005 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2005.

(b) Commitments for services, materials and information technology.

(c) Represents the present value of Generation’s obligation to decommission nuclear plants and conditional AROs recorded in connection with the adoption of FIN 47.

For additional information about:

• regulatory commitments, see Note 4 of Exelon’s Notes to Consolidated Financial Statements.

• commercial paper, see Note 10 of Exelon’s Notes to Consolidated Financial Statements.

• long-term debt, see Note 11 of Exelon’s Notes to Consolidated Financial Statements.

• capital lease obligations, see Note 11 of Exelon’s Notes to Consolidated Financial Statements.

• the spent nuclear fuel and decommissioning obligations, see Note 13 of Exelon’s Notes to Consolidated Financial Statements.

• the contribution required to Exelon’s pension plans to satisfy ERISA minimum funding requirements, see Note 15 of Exelon’s Notes to Consolidated Financial Statements.

• operating leases, energy commitments and fuel purchase agreements, see Note 20 of Exelon’s Notes to Consolidated Financial Statements.

• the obligation to minority shareholders, see Note 20 of Exelon’s Notes to Consolidated Financial Statements.

• asset retirement obligations, see Notes 13 and 14 of Exelon’s Notes to Consolidated Financial Statements.

Mystic Development, LLC (Mystic), a former affiliate of Exelon New England, has a long-term agreement through January 2020 with Distrigas of Massachusetts Corporation (Distrigas) for gas supply, primarily for the Boston Generating units. Under the agreement, gas purchase prices from Distrigas are indexed to the New England gas markets. Exelon New England has guaranteed Mystic’s

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financial obligations to Distrigas under the long-term supply agreement. Exelon New England’s guarantee to Distrigas remained in effect following the transfer of ownership interest in Boston Generating in May 2004. Under FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others (FIN 45),” approximately $14 million was included as a liability within the Consolidated Balance Sheets of Exelon as of December 31, 2005 related to this guarantee. The terms of the guarantee do not limit the potential future payments that Exelon New England could be required to make under the guarantee.

Generation has an obligation to decommission its nuclear power plants. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. Based on estimates of decommissioning costs for each of the nuclear facilities in which Generation has an ownership interest, the ICC permits ComEd, and the PAPUC 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. Generation also maintains nuclear decommissioning trust funds for each of the AmerGen units. Upon adoption of 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 to decommission nuclear generating facilities resulting from the passage of time are recorded as operating and maintenance expense. Increases in the asset retirement obligation resulting from a remeasurement are recorded with a corresponding ARC, which is a component of property, plant and equipment. At December 31, 2005, the asset retirement obligation recorded within Generation’s Consolidated Balance Sheets related to its nuclear-fueled generating facilities was approximately $4 billion. Decommissioning expenditures are expected to occur primarily after the plants are retired. Based on current licenses and anticipated renewals, decommissioning expenditures for plants in operation are currently estimated to begin after 2029. To fund future decommissioning costs, Generation held approximately $5.6 billion of investments in trust funds, including net unrealized gains and losses, at December 31, 2005. See Note 13 of Exelon’s Notes to Consolidated Financial Statements for further discussion of Generation’s decommissioning obligation.

See Note 20 of Exelon’s Notes to Consolidated Financial Statements for discussion of Exelon’s commercial commitments as of December 31, 2005.

Refund Claims

ComEd and PECO have several pending tax refund claims seeking acceleration of certain tax deductions and additional tax credits. ComEd and PECO are unable to estimate the ultimate outcome of these refund claims and will account for any amounts received in the period the matters are settled with the IRS and state taxing authorities.

ComEd and PECO had entered into several agreements with a tax consultant related to the filing of these refund claims with the IRS. ComEd and PECO previously made refundable prepayments to the tax consultants of $11 million and $5 million, respectively. The fees for these agreements are contingent upon a successful outcome of the claims and are based upon a percentage of the refunds recovered from the IRS if any. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of ComEd and PECO. A portion of ComEd’s tax benefits, including any associated interest for periods prior to the merger among PECO, Unicom Corporation (Unicom), the former parent company of ComEd, and Exelon (PECO / Unicom Merger) would be recorded as a reduction of goodwill pursuant to a reallocation of the PECO / Unicom Merger purchase price. ComEd and PECO cannot predict the timing of the final resolution of these refund claims.

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In 2004, the IRS granted preliminary approval for one of ComEd’s refund claims and final approval was obtained in the first quarter of 2005. The refund and associated interest have been recorded in the financial statements. Approximately $14 million of tax and interest benefit received in the second quarter of 2005 has been reflected in the financial statements of which $12 million ($9 million after tax) was recorded to goodwill under the provisions of EITF Issue 93-7, “Uncertainties Related to Income Taxes in a Purchase Business Combination.” As a result, ComEd recorded consulting expenses of $5 million (pre-tax) in 2004.

Based on negotiations with the IRS during the first half of 2005, PECO believed it would receive a tax refund related to one of its claims and recorded a $6 million (pre-tax) charge related to expected consulting fees during the first quarter of 2005. However, as the result of a recent unfavorable tax court decision involving another utility related to a similar type of refund claim, PECO no longer believes payment of the consulting fees is probable and reversed the $6 million (pre-tax) charge during the third quarter 2005. PECO is unable to predict the final impact of its future negotiations with the IRS on this matter.

Variable Interest Entities

Sithe.As of December 31, 2004, Generation was a 50% owner of Sithe. In accordance with FIN 46-R, Generation consolidated Sithe within its financial statements as of March 31, 2004. The determination that Sithe qualified as a variable interest entity and that Generation was the primary beneficiary under FIN 46-R required analysis of the economic benefits accruing to all parties pursuant to their ownership interests supplemented by management’s judgment. See Note 3 of Exelon’s Notes to Consolidated Financial Statements for a discussion of the sale of Generation’s entire interest in Sithe that was completed on January 31, 2005.

Financing Trusts of ComEd and PECO.During June 2003, PECO issued $103 million of subordinated debentures to PECO Trust IV in connection with the issuance by PECO Trust IV of $100 million of preferred securities. Effective July 1, 2003, PECO Trust IV was deconsolidated from the financial statements of PECO in conjunction with FIN 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.

Effective December 31, 2003, ComEd Financing II, ComEd Financing III, ComEd Funding, LLC, ComEd Transitional Funding Trust, PECO Trust III and PETT were deconsolidated from the financial statements of Exelon in conjunction with the adoption of FIN 46-R. Amounts of $1.3 billion and $3.1 billion, respectively, owed by ComEd and PECO to these financing trusts were recorded as long-term debt to ComEd Transitional Funding Trust and PETT and long-term debt to financing trusts within the Consolidated Balance Sheets as of December 31, 2005. See Other Subsidiaries of ComEd and PECO with Publicly Held Securities in Part I, ITEM 1 for further discussion of the nature, purpose and history of Exelon’s involvement with these financing trusts.

PECO 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 2010 based on the November 2005 amendment to this agreement. At December 31, 2005, PECO had sold a $225 million interest in accounts receivable, consisting of a $195 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 $30 million interest in special agreement accounts receivable, which PECO accounted for as a long-term note payable and

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reflected on the consolidated balance sheets as long-term debt due within one year. At December 31, 2004, PECO had sold a $225 million interest in accounts receivable, consisting of a $179 million interest in accounts receivable, which PECO accounted for as a sale under SFAS No. 140, and a $46 million interest in special agreement accounts receivable, which PECO accounted for as a long-term note payable and reflected on the consolidated balance sheets as long-term debt due within one year. 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, 2005 and 2004, PECO met this requirement and was not required to make any cash deposit.

Nuclear Insurance Coverage

Generation carries property damage, decontamination and premature decommissioning insurance for each station loss resulting from damage to Generation’s nuclear plants, subject to certain exceptions. Additionally, Generation carries business interruption insurance in the event of a major accidental outage at a nuclear station. Finally, 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. See Note 20 of Exelon’s Notes to Consolidated Financial Statements for further discussion of nuclear insurance. For its types of insured losses, Generation is self-insured to the extent that losses are within the policy deductible or 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 and cash flows.

New Accounting Pronouncements

See Note 1 of Exelon’s 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

Exelon is exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. Exelon’s RMC approves risk management policies and objectives 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 representing Exelon’s business units. The RMC reports to the Exelon Board of Directors on the scope of the derivative and risk management activities.

Commodity Price Risk (Exelon, ComEd and Generation)

To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, Exelon has price risk from commodity price movements. Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather, governmental regulatory and environmental policies, and other factors. Exelon seeks to mitigate its commodity price risk through the purchase and sale of electric capacity, energy and fossil fuels including oil, gas, coal and emission allowances. Within Exelon, Generation is primarily exposed to commodity price risk with ComEd having modest exposure due to the need to purchase ancillary services and the commodity price risk in relation to the CTC revenues collected from customers.

Generation

Generation’s energy contracts are accounted for under SFAS No. 133. Non-trading contracts qualify for the normal purchases and normal sales exemption to SFAS No. 133, which is discussed in Critical Accounting Policies and Estimates. Energy contracts that do not qualify for the normal purchases and normal sales exception 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 derivatives recorded at fair value are recognized in earnings unless specific hedge accounting criteria are met and they are designated as cash-flow hedges, in which case those changes are recorded in OCI, and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet the hedge criteria under SFAS No. 133 or are not designated as such are recognized in current earnings.

Normal Operations and Hedging Activities.Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including ComEd’s and PECO’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 anticipated exposures. The maximum length of time over which cash flows related to energy commodities are currently being cash-flow hedged is three years. Generation has an estimated 88% hedge ratio in 2006 for its energy marketing portfolio. This hedge ratio represents the percentage of its forecasted aggregate annual economic 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, energy market option volatility and actual loads. During peak periods, Generation’s amount hedged declines to meet its energy and capacity commitments to ComEd and PECO. Market price risk exposure is the risk of a change in the value of unhedged positions. Absent any efforts to mitigate market price exposure, the estimated market price exposure for Generation’s unhedged non-trading portfolio associated with a ten percent reduction in the annual average around-the-clock market price

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of electricity is approximately a $61 million decrease in net income. This sensitivity assumes an 88% 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.

In connection with the 2001 corporate restructuring, Generation entered into a PPA, as amended, with ComEd under which Generation has agreed to supply all of ComEd’s load obligations through 2006. At times, ComEd’s load obligations are greater than the capacity of Generation’s owned generating units in the ComEd region. As such, Generation procures power through purchase power and lease agreements and has contracted for access to additional generation through bilateral long-term PPAs. In 2004, Generation retained 3,858 MWs of capacity under the terms of three then-existing PPAs with Midwest Generation, LLC (Midwest Generation). Generation’s contract to purchase power from Midwest Generation expired at the end of 2004. As a result, Generation’s exposure to market price movements in the ComEd region in 2005 increased compared to 2004 due in part to the expiration of the Midwest Generation contract. Consequently, after 2004, Generation must procure the necessary power for ComEd through market purchases and other means to the extent not provided by Generation’s own generating facilities.

Following the expiration of the Illinois transition period and end of PPA between Generation and ComEd in 2006, all of Generation’s supply in the ComEd region will be available for sale into the wholesale markets and exposed to changes in market prices.

Proprietary Trading Activities.Generation began to use financial contracts for proprietary trading purposes in 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 Generation’s 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. Generation expects this level of proprietary trading activity to continue in the future. Trading portfolio activity for the year ended December 31, 2005 resulted in a gain of $17 million (before income taxes), which represented a net unrealized mark-to-market gain of $15 million and realized gain of $2 million. Generation uses a 95% confidence interval, one day holding period, one-tailed statistical measure in calculating its Value-at-Risk (VaR). The daily VaR on proprietary trading activity averaged $90,000 of exposure over the last 18 months. Because of the relative size of the proprietary trading portfolio in comparison to Generation’s total gross margin from continuing operations for year ended December 31, 2005 of $4,564 million, Generation has not segregated proprietary trading activity in the following tables. 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 proprietary trading activities.

Trading and Non-Trading Marketing Activities.The following detailed presentation of Generation’s trading and non-trading marketing activities at Generation is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officer (CCRO).

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The following table provides detail on changes in Generation’s mark-to-market net asset or liability balance sheet position from January 1, 2004 to December 31, 2005. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings as well as the settlements from OCI to earnings and changes in fair value for the hedging activities that are recorded in accumulated OCI on the Consolidated Balance Sheets.

	Total
Total mark-to-market energy contract net liabilities at January 1, 2004	$	(216	)
Total change in fair value during 2004 of contracts recorded in earnings		158
Reclassification to realized at settlement of contracts recorded in earnings		(197	)
Reclassification to realized at settlement from OCI		475
Effective portion of changes in fair value—recorded in OCI		(512	)
Purchase/sale/disposal of existing contracts or portfolios subject to mark-to-market		147
Total mark-to-market energy contract net liabilities at December 31, 2004(a)		(145	)
Total change in fair value during 2005 of contracts recorded in earnings		108
Reclassification to realized at settlement of contracts recorded in earnings		(105	)
Reclassification to realized at settlement from OCI		583
Effective portion of changes in fair value—recorded in OCI		(879	)
Purchase/sale/disposal of existing contracts or portfolios subject to mark-to-market		(102	)
Total mark-to-market energy contract net liabilities at December 31, 2005	$	(540	)

(a) Includes a $39 million liability related to Sithe and the related mark-to-market expense which were reclassified to discontinued operations.

The following table details the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of December 31, 2005 and 2004:

	December 31, 2005			December 31, 2004
Current assets	$	916		$	403
Noncurrent assets		286			373
Total mark-to-market energy contract assets		1,202			776
Current liabilities		(1,282	)		(598	)
Noncurrent liabilities		(460	)		(323	)
Total mark-to-market energy contract liabilities		(1,742	)		(921	)
Total mark-to-market energy contract net liabilities	$	(540	)	$	(145	)

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 mid-point 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, 2005 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
(in millions)	2006			2007			2008			2009		2010		2011 and Beyond		Total Fair Value
Normal Operations, qualifying cash-flow hedge contracts(a):
Actively quoted prices	$	2		$	1		$	—		$	—	$	—	$	—	$	3
Prices provided by other external sources		(388	)		(134	)		(2	)		—		—		—		(524	)
Total	$	(386	)	$	(133	)	$	(2	)	$	—	$	—	$	—	$	(521	)
Normal Operations, other derivative contracts(b):
Actively quoted prices	$	85		$	(57	)	$	5		$	—	$	—	$	—	$	33
Prices provided by other external sources		(43	)		25			(5	)		—		—		—		(23	)
Prices based on model or other valuation methods		(24	)		(5	)		—			—		—		—		(29	)
Total	$	18		$	(37	)	$	—		$	—	$	—	$	—	$	(19	)

(a) Mark-to-market gains and losses on contracts that qualify as cash-flow hedges are recorded in other comprehensive income.

(b) Mark-to-market gains and losses on other non-trading and trading derivative contracts that do not qualify as cash-flow hedges are recorded in earnings.

The table below provides details of effective cash-flow hedges under SFAS No. 133 included in the balance sheet as of December 31, 2005. 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 OCI related to cash-flow hedges for the years ended December 31, 2005 and December 31, 2004, 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 OCI Activity, Net of Income Tax
(in millions)	Power Team Normal Operations and Hedging Activities			Interest-Rate and Other Hedges			Total Cash- Flow Hedges
Accumulated OCI derivative loss at January 1, 2004	$	(133	)	$	(16	)	$	(149	)
Changes in fair value		(312	)		17			(295	)
Disposal of existing Boston Generating contracts		16			—			16
Reclassifications from OCI to net income		290			—			290
Exelon Energy Company opening balance		2			—			2
Sithe Energies, Inc. opening balance		—			(10	)		(10	)
Accumulated OCI derivative loss at December 31, 2004		(137	)		(9	)		(146	)
Changes in fair value		(533	)		5			(528	)
Reclassifications from OCI to net income		356			—			356
Accumulated OCI derivative loss at December 31, 2005	$	(314	)	$	(4	)	$	(318	)

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ComEd

ComEd has exposure to commodity price risk in relation to revenue collected from customers who elect to purchase energy from an alternative electric supplier 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.

ComEd’s CTC revenues are also collected from customers who elect to purchase energy from an alternative electric supplier. ComEd’s CTC rates are reset once a year in the spring, and customers can elect to lock in their CTC rates for a one or multiple year terms. ComEd anticipates that CTC revenues will range from $35 million to $50 million in 2006. Under current Illinois law, no CTCs will be collected after 2006.

ComEd also has exposure to commodity price risk in relation to ancillary services that are purchased from PJM. These services are not provided for in the current PPA between Generation and ComEd.

Credit Risk (Exelon, ComEd, PECO and Generation)

ComEd and PECO

Credit risk for ComEd and PECO is managed by credit and collection policies which are consistent with state regulatory requirements. ComEd and PECO are each currently obligated to provide service to all electric customers within their respective franchised territories. For the year ended December 31, 2005, ComEd’s ten largest customers represented approximately 3.5% of its electric revenues and PECO’s ten largest customers represented approximately 7.6% of its retail electric and gas revenues. ComEd and PECO record 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 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.

Generation

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

The following tables provide information on Generation’s credit exposure, net of collateral, as of December 31, 2005 and 2004. They further delineate that exposure by the credit rating of the

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counterparties and provide 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 tables below do not include sales to Generation’s affiliates or exposure through ISOs which are discussed below.

Rating as of December 31, 2005(a)	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	$	472	$	53	$	419	2	$	147
Non-investment grade		60		11		49	—		—
No external ratings
Internally rated—investment grade		41		—		41	—		—
Internally rated—non-investment grade		38		—		38	—		—
Total	$	611	$	64	$	547	2	$	147

(a) This table does not include accounts receivable exposure.

Rating as of December 31, 2004(a)	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	$	151	$	33	$	118	—	$	—
Non-investment grade		98		20		78	1		63
No external ratings
Internally rated—investment grade		13		—		13	—		—
Internally rated—non-investment grade		3		—		3	—		—
Total	$	265	$	53	$	212	1	$	63

(a) This table does not include accounts receivable exposure.

	Maturity of Credit Risk Exposure
Rating as of December 31, 2005(a)	Less than 2 Years		2-5 Years		Exposure Greater than 5 Years		Total Exposure Before Credit Collateral
Investment grade	$	472	$	—	$	—	$	472
Non-investment grade		56		4		—		60
No external ratings
Internally rated—investment grade		38		3		—		41
Internally rated—non-investment grade		17		14		7		38
Total	$	583	$	21	$	7	$	611

(a) This table does not include accounts receivable exposure.

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 and its counterparties 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

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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 the 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 that are administered by ISOs: PJM, ISO New England, New York ISO, MISO, Southwest Power Pool, Inc. and 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.

Exelon

Exelon’s consolidated balance sheets included a $507 million net investment in direct financing leases as of December 31, 2005. The investment in direct financing leases represents future minimum lease payments due at the end of the thirty-year lives of the leases of $1,492 million, less unearned income of $985 million. The future minimum lease payments are supported by collateral and credit enhancement measures including letters of credit, surety bonds and credit swaps issued by high credit quality financial institutions. Management regularly evaluates the credit worthiness of Exelon’s counterparties to these direct financing leases.

Interest-Rate Risk (Exelon, ComEd, PECO and Generation)

Variable Rate Debt.The Registrants use a combination of fixed-rate and variable-rate debt to reduce interest-rate exposure. The Registrants also use interest-rate swaps when deemed appropriate to adjust exposure based upon market conditions. Additionally, the Registrants use forward-starting interest-rate swaps and treasury rate locks to lock in interest-rate levels in anticipation of future financings. These strategies are employed to achieve a lower cost of capital. As of December 31, 2005, a hypothetical 10% increase in the interest rates associated with variable-rate debt would result in a $3 million, $1 million and $2 million decrease in Exelon’s, ComEd’s and Generation’s, respectively, pre-tax earnings. A hypothetical 10% increase in the interest rates associated with variable-rate debt would result in a decrease in pre-tax earnings of less than $1 million at PECO.

Fair-Value Hedges.At December 31, 2005, ComEd had interest-rate swaps designated as fair-value hedges in the aggregate notional amount of $240 million. At December 31, 2005, these interest-rate swaps had an aggregate fair market value of $(1) million based on the present value difference between the contract and market rates at December 31, 2005. If these derivative instruments had been terminated at December 31, 2005, this estimated fair value represents the amount ComEd would pay the counterparties. On January 17, 2006, ComEd settled these swaps and paid $1 million.

The aggregate fair value of ComEd’s 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,

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2005 is estimated to be a favorable impact to ComEd of $5 million. If these derivative instruments had been terminated at December 31, 2005, this estimated fair value represents the amount counterparties would pay ComEd.

The aggregate fair value of ComEd’s 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, 2005 is estimated to be a favorable impact to the counterparties of $7 million. If these derivative instruments had been terminated at December 31, 2005, this estimated fair value represents the amount ComEd would pay the counterparties.

Cash-Flow Hedges. During 2005, ComEd entered into five forward-starting interest-rate swaps in the aggregate notional amount of $325 million to lock in interest-rate levels in anticipation of a future financing. At the time of the swap trades, the debt issuance that these swaps were hedging was considered probable; therefore, ComEd accounted for these interest-rate swap transactions as cash-flow hedges. However, in September 2005, the future financing was postponed indefinitely and consequently, ComEd unwound the $325 million forward-starting interest-rate swaps and paid the counterparties approximately $15 million. As a result, Exelon and ComEd recognized a pre-tax loss of $15 million which was included in other, net within the Consolidated Statements of Income. In addition, during 2005, Exelon settled interest-rate swaps in the aggregate notional amount of $1.5 billion and recorded pre-tax losses of $39 million which will be recorded as additional interest expense over the remaining life of the related debt.

Equity Price Risk (Exelon and Generation)

Generation maintains trust funds, as required by the NRC, to fund certain costs of decommissioning Generation’s nuclear plants.As of December 31, 2005, Generation’s decommissioning trust funds are reflected at fair value on its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation 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 Generation’s nuclear decommissioning trust fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $391 million reduction in the fair value of the trust assets. See Defined Benefit Pension and Other Postretirement Welfare Benefits in the Critical Accounting Estimates section for information regarding the pension and other postretirement benefit trust assets.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Exelon

Management’s Report on Internal Control Over Financial Reporting

The management of Exelon Corporation (Exelon) is responsible for establishing and maintaining adequate internal control over financial reporting. Exelon’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Exelon’s management conducted an assessment of the effectiveness of Exelon’s internal control over financial reporting as of December 31, 2005. In making this assessment, management used the criteria inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Exelon’s management concluded that, as of December 31, 2005, Exelon’s internal control over financial reporting was effective.

Management’s assessment of the effectiveness of Exelon’s internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on the next page of this Annual Report on Form 10-K.

February 15, 2006

157

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of Exelon Corporation:

We have completed integrated audits of Exelon Corporation’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedule

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1)(i) present fairly, in all material respects, the financial position of Exelon Corporation and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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)(1)(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 the Company’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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements 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, Exelon Corporation changed its method of accounting for asset retirement obligations as of January 1, 2003, its method of accounting for variable interest entities in 2003 and 2004; and its method of accounting for conditional asset retirement obligations as of December 31, 2005.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial

158

reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP

Chicago, Illinois

February 15, 2006

159

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Income

	For the Years Ended December 31,
(in millions, except per share data)	2005			2004			2003
Operating revenues	$	15,357		$	14,133		$	15,148
Operating expenses
Purchased power		3,162			2,709			3,459
Purchased power from AmerGen Energy Company, LLC		—			—			382
Fuel		2,484			2,220			2,353
Operating and maintenance		3,718			3,700			3,915
Impairment of goodwill		1,207			—			—
Impairment of Boston Generating, LLC long-lived assets		—			—			945
Depreciation and amortization		1,334			1,295			1,115
Taxes other than income		728			710			570
Total operating expenses		12,633			10,634			12,739
Operating income		2,724			3,499			2,409
Other income and deductions
Interest expense		(513	)		(471	)		(861	)
Interest expense to affiliates		(316	)		(357	)		(12	)
Distributions on preferred securities of subsidiaries		(4	)		(3	)		(39	)
Equity in earnings (losses) of unconsolidated affiliates		(134	)		(154	)		33
Other, net		138			63			(244	)
Total other income and deductions		(829	)		(922	)		(1,123	)
Income from continuing operations before income taxes and minority interest		1,895			2,577			1,286
Income taxes		944			713			389
Income from continuing operations before minority interest		951			1,864			897
Minority interest		—			6			(5	)
Income from continuing operations		951			1,870			892
Discontinued operations
Loss from discontinued operations (net of taxes of $(3), $(40) and $(49) in 2005, 2004 and 2003, respectively)		(4	)		(61	)		(86	)
Gain (loss) on disposal of discontinued operations (net of taxes of $6, $19 and $(9) in 2005, 2004 and 2003, respectively)		18			32			(13	)
Income (loss) from discontinued operations		14			(29	)		(99	)
Income before cumulative effect of changes in accounting principles		965			1,841			793
Cumulative effect of changes in accounting principles (net of income taxes of $(27), $17 and $69 in 2005, 2004 and 2003, respectively)		(42	)		23			112
Net income	$	923		$	1,864		$	905
Average shares of common stock outstanding
Basic		669			661			651
Diluted		676			669			657
Earnings per average common share—basic:
Income from continuing operations	$	1.42		$	2.83		$	1.37
Income (loss) from discontinued operations		0.02			(0.04	)		(0.15	)
Income before cumulative effect of changes in accounting principles		1.44			2.79			1.22
Cumulative effect of changes in accounting principles		(0.06	)		0.03			0.17
Net income	$	1.38		$	2.82		$	1.39
Earnings per average common share—diluted:
Income from continuing operations	$	1.40		$	2.79		$	1.36
Income (loss) from discontinued operations		0.02			(0.04	)		(0.15	)
Income before cumulative effect of changes in accounting principles		1.42			2.75			1.21
Cumulative effect of changes in accounting principles		(0.06	)		0.03			0.17
Net income	$	1.36		$	2.78		$	1.38
Dividends per common share	$	1.60		$	1.26		$	0.96

See Notes to Consolidated Financial Statements

160

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Cash Flows

	For the Years Ended December 31,
(in millions)	2005			2004			2003
Cash flows from operating activities
Net income	$	923		$	1,864		$	905
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel		1,967			1,933			1,681
Cumulative effect of changes in accounting principles (net of income taxes)		42			(23	)		(112	)
Impairment of investments		—			10			309
Impairment of goodwill		1,207			—			24
Impairment of long-lived assets		—			1			966
Deferred income taxes and amortization of investment tax credits		493			202			(36	)
Provision for uncollectible accounts		77			87			94
Equity in (earnings) losses of unconsolidated affiliates		134			153			(33	)
(Gains) losses on sales of investments and wholly owned subsidiaries		(22	)		(162	)		25
Net realized (gains) losses on nuclear decommissioning trust funds		(49	)		(72	)		16
Other decommissioning-related activities		(15	)		169			37
Other non-cash operating activities		76			(24	)		18
Changes in assets and liabilities
Accounts receivable		(279	)		(123	)		102
Inventories		(118	)		(60	)		(54	)
Other current assets		(168	)		46			12
Accounts payable, accrued expenses and other current liabilities		172			133			(87	)
Disbursements of counterparty collateral		(244	)		42			(72	)
Collections of counterparty collateral		57			31			5
Income taxes		138			293			(271	)
Net realized and unrealized mark-to-market and hedging transactions		(30	)		49			(10	)
Pension and non-pension postretirement benefits obligation		(2,003	)		(270	)		(144	)
Other noncurrent assets and liabilities		(211	)		119			9
Net cash flows provided by operating activities		2,147			4,398			3,384
Cash flows from investing activities
Capital expenditures		(2,165	)		(1,921	)		(1,954	)
Proceeds from liquidated damages		—			—			92
Proceeds from nuclear decommissioning trust fund sales		5,274			2,320			2,341
Investment in nuclear decommissioning trust funds		(5,501	)		(2,587	)		(2,564	)
Acquisitions of businesses, net of cash acquired		(97	)		—			(272	)
Proceeds from sales of investments and wholly owned subsidiaries, net of $32 of cash sold during 2005		105			329			263
Proceeds from sales of long-lived assets		2			52			10
Investments in synthetic fuel-producing facilities		(102	)		(56	)		—
Change in restricted cash		21			52			(118	)
Collection of other notes receivable		—			59			35
Net cash increase from consolidation of Sithe Energies, Inc.		—			19			—
Other investing activities		(24	)		(6	)		32
Net cash flows used in investing activities		(2,487	)		(1,739	)		(2,135	)
Cash flows from financing activities
Issuance of long-term debt		1,788			232			3,015
Retirement of long-term debt		(508	)		(1,629	)		(2,922	)
Issuance of long-term debt to financing affiliates		—			—			103
Retirement of long-term debt to financing affiliates		(835	)		(728	)		—
Issuance of short-term debt		2,500			—			—
Retirement of short-term debt		(2,200	)		—			—
Change in short-term debt		500			164			(355	)
Issuance of mandatorily redeemable preferred securities		—			—			200
Retirement of mandatorily redeemable preferred securities		—			—			(250	)
Payment on acquisition note payable to Sithe Energies, Inc.		—			(27	)		(446	)
Retirement of preferred stock		—			—			(50	)
Dividends paid on common stock		(1,070	)		(831	)		(620	)
Proceeds from employee stock plans		222			240			181
Purchase of treasury stock		(362	)		(82	)		—
Other financing activities		(54	)		34			(96	)
Net cash flows used in financing activities		(19	)		(2,627	)		(1,240	)
Increase (decrease) in cash and cash equivalents		(359	)		32			9
Cash and cash equivalents at beginning of period		499			467			469
Cash and cash equivalents, including cash held for sale		140			499			478
Cash classified as held for sale on the consolidated balance sheet		—			—			11
Cash and cash equivalents at end of period	$	140		$	499		$	467

See Notes to Consolidated Financial Statements

161

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets

	December 31,
(in millions)	2005		2004
Assets
Current assets
Cash and cash equivalents	$	140	$	499
Restricted cash and investments		49		60
Accounts receivable, net
Customer		1,858		1,649
Other		337		409
Mark-to-market derivative assets		916		403
Inventories, at average cost
Fossil fuel		311		230
Materials and supplies		351		312
Deferred income taxes		80		68
Other		595		250
Total current assets		4,637		3,880
Property, plant and equipment, net		21,981		21,482
Deferred debits and other assets
Regulatory assets		4,386		4,790
Nuclear decommissioning trust funds		5,585		5,262
Investments		813		804
Goodwill		3,475		4,705
Mark-to-market derivative assets		311		383
Prepaid pension asset		377		—
Other		824		1,418
Total deferred debits and other assets		15,771		17,362
Total assets	$	42,389	$	42,724

See Notes to Consolidated Financial Statements

162

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets

	December 31,
(in millions)	2005			2004
Liabilities and shareholders’ equity
Current liabilities
Commercial paper and notes payable	$	1,290		$	490
Long-term debt due within one year		407			427
Long-term debt to ComEd Transitional Funding Trust and PECO Energy Transitional Trust due within one year		507			486
Accounts payable		1,467			1,255
Mark-to-market derivative liabilities		1,282			598
Accrued expenses		1,005			1,097
Other		605			483
Total current liabilities		6,563			4,836
Long-term debt		7,759			7,292
Long-term debt due to ComEd Transitional Funding Trust and PECO Energy Transitional Trust		3,456			4,311
Long-term debt to other financing trusts		545			545
Deferred credits and other liabilities
Deferred income taxes		4,816			4,488
Unamortized investment tax credits		262			275
Asset retirement obligations		4,157			3,981
Pension obligations		268			1,993
Non-pension postretirement benefits obligations		1,014			1,065
Spent nuclear fuel obligation		906			878
Regulatory liabilities		2,170			2,204
Mark-to-market derivative liabilities		462			323
Other		798			915
Total deferred credits and other liabilities		14,853			16,122
Total liabilities		33,176			33,106
Commitments and contingencies
Minority interest of consolidated subsidiaries		1			42
Preferred securities of subsidiaries		87			87
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 666.4 and 664.2 shares outstanding at December 31, 2005 and 2004, respectively)		7,987			7,664
Treasury stock, at cost (9.4 and 2.5 shares held at December 31, 2005 and 2004, respectively)		(444	)		(82	)
Retained earnings		3,206			3,353
Accumulated other comprehensive loss		(1,624	)		(1,446	)
Total shareholders’ equity		9,125			9,489
Total liabilities and shareholders’ equity	$	42,389		$	42,724

See Notes to Consolidated Financial Statements

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Consolidated Statements of Changes in Shareholders’ Equity

(Dollars in millions, shares in thousands)	Issued Shares	Common Stock		Treasury Stock			Deferred Compensation			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity
Balance, December 31, 2002	646,626	$	7,092	$	—		$	(1	)	$	2,042		$	(1,358	)	$	7,775
Net income	—		—		—			—			905			—			905
Long-term incentive plan activity	9,322		244		—			—			—			—			244
Employee stock purchase plan issuances	418		11		—			—			—			—			11
Amortization of deferred compensation	—		—		—			1			—			—			1
Common stock dividends declared	—		—		—			—			(625	)		—			(625	)
Redemption premium on PECO preferred stock	—		—		—			—			(2	)		—			(2	)
Other comprehensive income, net of income taxes of $217	—		—		—			—			—			249			249
Balance, December 31, 2003	656,366		7,347		—			—			2,320			(1,109	)		8,558
Net income	—		—		—			—			1,864			—			1,864
Long-term incentive plan activity	10,013		307		—			—			—			—			307
Employee stock purchase plan issuances	309		10		—			—			—			—			10
Common stock purchases	—		—		(82	)		—			—			—			(82	)
Common stock dividends declared	—		—		—			—			(831	)		—			(831	)
Adjustments to accumulated other comprehensive loss due to the consolidation of Sithe	—		—		—			—			—			(6	)		(6	)
Other comprehensive loss, net of income taxes of $(190)	—		—		—			—			—			(331	)		(331	)
Balance, December 31, 2004	666,688		7,664		(82	)		—			3,353			(1,446	)		9,489
Net income	—		—		—			—			923			—			923
Long-term incentive plan activity	8,862		311		—			—			—			—			311
Employee stock purchase plan issuances	259		12		—			—			—			—			12
Common stock purchases	—		—		(362	)		—			—			—			(362	)
Common stock dividends declared	—		—		—			—			(1,070	)		—			(1,070	)
Other comprehensive loss, net of income taxes of $(127)	—		—		—			—			—			(178	)		(178	)
Balance, December 31, 2005	675,809	$	7,987	$	(444	)	$	—		$	3,206		$	(1,624	)	$	9,125

See Notes to Consolidated Financial Statements

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Consolidated Statements of Comprehensive Income

	For the Years Ended December 31,
(in millions)	2005			2004			2003
Net income	$	923		$	1,864		$	905
Other comprehensive income (loss)
Minimum pension liability, net of income taxes of $3, $(228) and $16, respectively		10			(392	)		26
SFAS No. 143 transition adjustment, net of income taxes of $167		—			—			168
Change in net unrealized gain (loss) on cash-flow hedges, net of income taxes of $(133), $6 and $5, respectively		(199	)		8			9
Foreign currency translation adjustment, net of income taxes of $(1), $1 and $0, respectively		(3	)		1			3
Unrealized gain on marketable securities, net of income taxes of $4, $31 and $29, respectively		14			52			43
Total other comprehensive income (loss)		(178	)		(331	)		249
Total comprehensive income	$	745		$	1,533		$	1,154

See Notes to Consolidated Financial Statements

165

Exelon Corporation 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

Exelon Corporation (Exelon) is a utility services holding company engaged, through its subsidiaries, in the energy delivery, generation and other businesses discussed below. The energy delivery businesses include the purchase and regulated retail and wholesale sale of electricity and distribution and transmission services by Commonwealth Edison Company (ComEd) in northern Illinois, including the City of Chicago, and by PECO Energy Company (PECO) in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and related distribution services by PECO in the Pennsylvania counties surrounding the City of Philadelphia. The generation business consists principally of the electric generating facilities and wholesale energy marketing operations of Exelon Generation Company, LLC (Generation), the competitive retail sales business of Exelon Energy Company (Exelon Energy) and certain other generation projects. Exelon Energy, which had been previously included in the Enterprises segment, became part of Generation effective January 1, 2004. Exelon sold or wound down substantially all components of Exelon Enterprises Company, LLC (Enterprises) in 2004 and 2003. As a result, as of January 1, 2005, Enterprises is no longer reported as a segment. See Note 3—Acquisitions and Dispositions for information regarding the disposition of businesses within the Enterprises segment and Note 22—Segment Information for information regarding Exelon’s reportable segments.

Basis of Presentation

Exelon’s consolidated financial statements include the accounts of entities in which it has a controlling financial interest, other than certain financing trusts of ComEd and PECO described below, and its proportionate interests in jointly owned electric utility plants, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% or a risk and rewards model that identifies Exelon or one of its subsidiaries as the primary beneficiary of the variable interest entity. Investments and joint ventures in which Exelon does not have a controlling financial interest and certain financing trusts of ComEd and PECO are accounted for under the equity or cost methods of accounting.

Exelon owns 100% of all significant consolidated subsidiaries, either directly or indirectly, except for ComEd, of which Exelon owns more than 99%, and Southeast Chicago Energy Project, LLC (SCEP), of which Exelon owns 72%. Exelon has reflected the third-party interests in the above majority-owned investments as minority interests in its consolidated financial statements.

In accordance with FASB Interpretation No. (FIN) 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN 46-R), Sithe Energies, Inc. (Sithe) was consolidated in Exelon’s financial statements as of March 31, 2004. As further discussed in Note 3—Acquisitions and Dispositions, Generation sold its investment in Sithe on January 31, 2005. Certain trusts and limited partnerships that are financing subsidiaries of ComEd and PECO have issued debt or mandatorily redeemable preferred securities. Due to the adoption of FIN 46-R, these subsidiaries are no longer consolidated as of December 31, 2003, or as of July 1, 2003 for PECO Energy Capital Trust IV (PECO Trust IV). See “Variable Interest Entities” below for further discussion of the adoption of FIN 46-R and the resulting consolidation of Sithe and the deconsolidation of these financing subsidiaries.

The share and per-share amounts included in Exelon’s Notes to Consolidated Financial Statements have been adjusted for all periods presented to reflect a 2-for-1 stock split of Exelon’s common stock with a distribution date of May 5, 2004. See Note 18—Common Stock for additional information regarding the stock split.

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Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Reclassifications

Certain prior year amounts have been reclassified in the financial statements for comparative purposes. The reclassifications did not affect net income.

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 nuclear decommissioning costs and asset retirement obligations, inventory reserves, allowance for doubtful accounts, goodwill and asset impairments, pension and other postretirement benefits, derivative instruments, fixed asset depreciation, environmental costs, taxes, severance and unbilled energy revenues.

Accounting for the Effects of Regulation

Exelon accounts for its regulated operations in accordance with accounting policies prescribed by the regulatory authorities having jurisdiction, principally the Illinois Commerce Commission (ICC) and the Pennsylvania Public Utility Commission (PAPUC) under state public utility laws, the Federal Energy Regulatory Commission (FERC) under various Federal laws, and the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA) prior to its repeal effective February 8, 2006, and ComEd and PECO apply SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” (SFAS No. 71). SFAS No. 71 requires ComEd and PECO to record in its financial statements the effects of rate regulation for 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. Exelon believes that it is probable that its currently recorded regulatory assets and liabilities will be recovered in future rates. However, Exelon continues to evaluate ComEd’s and PECO’s abilities to apply SFAS No. 71, including, in the case of ComEd, incorporating the current events related to the regulatory and political environment in Illinois. If a separable portion of ComEd’s or PECO’s business were no longer to meet the provisions of SFAS No. 71, Exelon would be required to eliminate from its financial statements the effects of regulation for that portion, which could have a material impact on its financial condition and results of operations. See Note 4—Regulatory Issues for further information regarding the repeal of PUHCA effective February 8, 2006.

Variable Interest Entities

FIN 46 and its revision FIN 46-R addressed the requirements for consolidating certain variable interest entities. FIN 46 was effective for Exelon’s variable interest entities created after January 31, 2003. FIN 46-R was effective December 31, 2003 for Exelon’s variable interest entities that were considered to be special-purpose entities and as of March 31, 2004 for all other variable interest entities.

Exelon consolidated Sithe, 50% owned through a wholly owned subsidiary of Generation, as of March 31, 2004 pursuant to the provisions of FIN 46-R and recorded income of $32 million (net of

167

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

income taxes) as a result of the reversal of guarantees of Sithe’s commitments previously recorded by Generation. This income was reported as a cumulative effect of a change in accounting principle in the first quarter of 2004. As of March 31, 2004, Generation was a 50% owner of Sithe, and Exelon had accounted for Sithe as an unconsolidated equity method investment prior to March 31, 2004. Sithe owns and operates power-generating facilities and was sold by Generation on January 31, 2005. See Note 3—Acquisitions and Dispositions for additional information regarding the sale of Sithe in 2005.

PECO Trust IV, a financing subsidiary of PECO created in May 2003, was deconsolidated from the financial statements of Exelon pursuant to the provisions of FIN 46 as of July 1, 2003. Pursuant to the provisions of FIN 46-R, as of December 31, 2003, the financing trusts of ComEd, namely ComEd Financing II (formed in November 1996), ComEd Financing III (formed in September 2002), ComEd Funding LLC (formed in July 1998) and ComEd Transitional Funding Trust (formed in October 1998), and the other financing trusts of PECO, namely PECO Trust III (formed in April 1998) and PETT (formed in June 1998), were deconsolidated from Exelon���s financial statements. Amounts owed to these financing trusts at December 31, 2005 and 2004 of $4.5 billion and $5.3 billion, respectively, were recorded as debt to financing trusts within Exelon’s Consolidated Balance Sheets.

This change in presentation related to the financing trusts had no effect on Exelon’s net income. In accordance with FIN 46-R, prior periods were not restated. The maximum exposure to loss as a result of ComEd’s and PECO’s involvement with the financing trusts was $46 million and $73 million, respectively, at December 31, 2005 and was $62 million and $87 million, respectively, at December 31, 2004.

Revenues

Operating Revenues.Operating revenues are recorded as service is rendered or energy is delivered to customers. At the end of each month, Exelon accrues an estimate for the unbilled amount of energy delivered or services provided to customers (see Note 5—Accounts Receivable).

Option Contracts, Swaps, and Commodity Derivatives.Premiums received and paid on option contracts and swap arrangements considered “normal” derivatives pursuant to SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133) are amortized to revenue and expensed over the lives of the contracts. Certain option contracts and swap arrangements 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 with unrealized gains and losses recognized in operating revenues.

Trading Activities. Exelon accounts for its trading activities under 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 requires revenues and energy costs related to energy trading contracts to be presented on a net basis in the income statement.

Physically Settled Derivative Contracts.Exelon accounts for realized gains and losses on physically settled derivative contracts not “held for trading purposes” in accordance with 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

168

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

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).

EITF 03-11 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. Exelon adopted EITF 03-11 as of January 1, 2004 and presented purchased power and fuel expense net within revenues of $1,061 million and $38 million, respectively, during 2005, and $966 million and $14 million, respectively, during 2004. Prior periods were not reclassified. The adoption of EITF 03-11 had no effect on Exelon’s net income. Had EITF 03-11 been retroactively applied to 2003, operating revenues, purchased power and fuel expense would have been affected as follows:

2003	As Reported		EITF 03-11 Impact			Pro Forma
Operating revenue	$	15,148	$	(996	)	$	14,152
Purchased power		3,841		(943	)		2,898
Fuel expense		2,353		(53	)		2,300

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 benefits carried forward. 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.

Pursuant to the Internal Revenue Code, Exelon files a consolidated Federal income tax return that includes its subsidiaries in which it owns at least 80% of the outstanding stock. Income taxes are allocated to each of Exelon’s subsidiaries included in the filing of the consolidated Federal income tax return based on the separate return method. Exelon records an income tax valuation allowance for deferred tax assets which are not more likely than not to be realized in the future (see Note 12—Income Taxes).

Losses on Reacquired Debt

Recoverable 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 rate-making purposes. Losses on other reacquired debt are recognized in Exelon’s Consolidated Statements of Income as incurred (see Note 21—Supplemental Financial Information).

Comprehensive Income

Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to shareholders. Other comprehensive income primarily relates to unrealized gains or losses on securities held in nuclear decommissioning trust funds, unrealized gains and losses on cash-flow hedge instruments and the minimum pension liability. Comprehensive income is reflected in the Consolidated Statements of Changes in Shareholders’ Equity and the Consolidated Statements of Comprehensive Income.

169

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Cash and Cash Equivalents

Exelon considers all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents.

Restricted Cash and Investments

As of December 31, 2005, restricted cash and investments primarily represented restricted funds for payment of medical, dental, vision and long-term disability benefits. As of December 31, 2004, restricted cash related to Sithe’s Independence Plant partnership distribution fund. On January 31, 2005, Generation sold its investment in Sithe.

Restricted cash and investments not available for general operations or to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2005, Exelon did not have any noncurrent restricted cash and investments. As of December 31, 2004, $93 million of restricted cash and investments were classified within Exelon’s deferred debits and other assets, which included $83 million of debt service reserves, major overhaul reserves of $7 million and lease service reserves of $3 million.

Allowance for Doubtful Accounts

The allowance for doubtful accounts reflects Exelon’s best estimate of probable losses in the accounts receivable balances. The allowance is based on known troubled accounts, historical experience and other currently available evidence. Customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, typically monthly. Customer accounts are written off based upon approved regulatory requirements.

Inventories

Inventory is recorded at the lower of cost or market, and provisions are made for excess and obsolete inventory.

Fossil Fuel.Fossil fuel inventory includes the weighted average costs of stored natural gas, propane, coal and oil. The costs of natural gas, propane, coal and oil are generally included in inventory when purchased and charged to fuel expense when used. PECO has several long-term storage contracts for natural gas as well as a liquefied natural gas storage facility.

Materials and Supplies. Materials and supplies inventory generally includes the average costs of transmission, distribution and generating plant materials. Materials are generally charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

Emission Allowances

Emission allowances are included in inventories and other deferred debits and are carried at the lower of weighted average cost or market and charged to fuel expense as they are used in operations. Exelon’s emission allowance balances as of December 31, 2005 and 2004 were $112 million and $106 million, respectively.

170

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Marketable Securities

Marketable securities are classified as available-for-sale securities and are reported at fair value pursuant to SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS No. 115). Realized and unrealized gains and losses, net of tax, on nuclear decommissioning trust funds transferred to Generation from PECO and ComEd are considered in the determination of the regulatory assets and liabilities. See Note 21—Supplemental Financial Information for additional information regarding ComEd’s and PECO’s regulatory assets and liabilities. Realized and unrealized gains and losses on nuclear decommissioning trust funds for the AmerGen units are reported in other comprehensive income. At December 31, 2005 and 2004, Exelon had no held-to-maturity securities. See Note 13—Nuclear Decommissioning and Spent Fuel Storage for information regarding marketable securities held by nuclear decommissioning trust funds.

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. At December 31, 2005 and 2004, deferred energy costs of $39 million and $25 million, respectively, were recorded as current assets on Exelon’s Consolidated Balance Sheets.

Leases

Exelon accounts for leases in accordance with SFAS No. 13, “Accounting for Leases” and determines whether its long-term purchase power and sales contracts are leases pursuant to EITF Issue No. 01-8, “Determining Whether an Arrangement is a Lease” (EITF 01-8). At the inception of the lease, or subsequent modification, Exelon determines whether the lease is an operating or capital lease based upon its terms and characteristics. Several of Exelon’s long-term purchase power agreements which have been determined to be operating leases have significant contingent rental payments that are dependent on the future operating characteristics of the associated plants such as plant availability. Exelon recognizes contingent rental expense when it becomes probable of payment.

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.

For ComEd and PECO, upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation in accordance with the composite method of depreciation. For ComEd, removal costs reduce the related regulated liability. For PECO, removal costs are capitalized when incurred and depreciated over the life of the new asset constructed consistent with PECO’s regulatory recovery method. For unregulated property, the cost and accumulated depreciation of property, plant and equipment retired or otherwise disposed of are removed from the related accounts.

For Generation, upon retirement, the cost of property is charged to accumulated depreciation.

171

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

See Note 6—Property, Plant and Equipment and Note 21—Supplemental Financial Information for additional information regarding property, plant and equipment.

Nuclear Fuel

The cost of nuclear fuel is capitalized and charged to fuel expense using the unit-of-production method. The estimated cost of disposal of Spent Nuclear Fuel (SNF) is established per the Standard Waste Contract with the Department of Energy (DOE) and is expensed at one mill ($.001) per kilowatthour of net nuclear generation. On-site SNF storage costs are capitalized or expensed, as incurred, based upon the nature of the work performed.

Nuclear Outage Costs

Costs associated with nuclear outages are recorded in the period incurred.

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, 2005 and 2004, net unamortized capitalized software costs totaled $264 million and $311 million, respectively. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed ten years. Certain capitalized software costs are being amortized over five to fifteen years pursuant to regulatory approval. During 2005, 2004 and 2003, Exelon amortized capitalized software costs of $76 million, $80 million and $69 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, presented by average service life and as a percentage of average service life for each asset category, are presented in the tables below. See Note 6—Property, Plant and Equipment for information regarding a change in ComEd’s and PECO’s depreciation rates.

Average Service Life in Years by Asset Category	2005	2004	2003
Electric—transmission and distribution	5-75	5-75	8-75
Electric—generation	5-62	5-63	5-64
Gas	5-85	5-85	8-85
Common—electric and gas	5-46	5-46	6-46
Other property and equipment	5-58	5-58	5-58
Average Service Life Percentage by Asset Category	2005	2004	2003
Electric—transmission and distribution	2.79%	2.82%	2.81%
Electric—generation	3.59%	3.34%	2.90%
Gas	2.32%	2.52%	2.38%
Common—electric and gas	8.06%	4.60%	7.53%
Other property and equipment	6.97%	6.77%	8.20%

172

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Amortization of regulatory assets is provided over the recovery period specified in the related legislation or regulatory agreement. See Note 21—Supplemental Financial Information for further information regarding the amortization of regulatory assets, nuclear fuel, asset retirement obligation and intangible assets.

Nuclear Generating Station Decommissioning

Exelon accounts for the costs of decommissioning its nuclear generating stations in accordance with SFAS No. 143. See Note 13—Nuclear Decommissioning and Spent Fuel Storage for information regarding the adoption and application of SFAS No. 143.

Capitalized Interest and Allowance for Funds Used During Construction

Exelon applies SFAS No. 34, “Capitalizing Interest Costs” to calculate the costs during construction of debt funds used to finance its non-regulated construction projects. Exelon capitalized interest of $12 million, $11 million and $15 million in 2005, 2004 and 2003, respectively.

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 is recorded as a charge to construction work in progress and as a non-cash credit to AFUDC that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities (see Note 21—Supplemental Financial Information). Exelon recorded credits to AFUDC of $10 million, $5 million and $16 million in 2005, 2004 and 2003, respectively.

Guarantees

Beginning February 1, 2003, pursuant to FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others (FIN 45),” Exelon recognizes, at the inception of a guarantee, a liability for the fair market value of the obligations it has undertaken in issuing the guarantee, including the ongoing obligation to perform over the term of the guarantee in the event that the specified triggering events or conditions occur.

The liability that is initially recognized at the inception of the guarantee is reduced as Exelon is released from risk under the guarantee. Depending on the nature of the guarantee, Exelon’s release from risk may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. The recognition and subsequent adjustment of the liability are highly dependent upon the nature of the associated guarantee.

Asset Impairments

Long-Lived Assets.Exelon 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 3—Acquisitions and Dispositions for a description of the impairment charge recorded in 2003 related to the long-lived assets of Boston Generating, LLC (Boston Generating).

173

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Upon meeting certain criteria defined in SFAS No. 144, the assets and associated liabilities that compose a disposal group are classified as held for sale and presented separately on the Consolidated Balance Sheets. The carrying value of these assets is adjusted downward, if necessary, to the estimated sales price, less cost to sell.

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. Pursuant to SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142), goodwill is not 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. See Note 8—Intangible Assets for information regarding the adoption of SFAS No. 142 and the results of goodwill impairment studies that have been performed, which include the $1.2 billion goodwill impairment charge recorded in 2005.

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, Exelon evaluates, among other factors, 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. Exelon 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—Acquisitions and Dispositions for a description of the impairments recorded in 2003 related to Generation’s investment in Sithe and Note 16—Fair Value of Financial Assets and Liabilities for a description of the other-than-temporary impairments in the nuclear decommissioning trust funds determined in 2005 and 2004.

Derivative Financial Instruments

Exelon enters into derivatives to manage its exposure to fluctuations in interest rates, changes in interest rates related to planned future debt issuances and changes in the fair value of outstanding debt. Generation utilizes derivatives with respect to energy transactions to manage the utilization of its available generating capability and the supply 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. Exelon’s derivative activities are in accordance with Exelon’s Risk Management Policy (RMP).

Exelon accounts for derivative financial instruments under 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 or normal sales exception. Derivatives on the balance sheet are presented as current or noncurrent mark-to-market derivative assets or liabilities. Changes in the fair value of derivatives are recognized in earnings unless specific hedge accounting criteria are met, in which case those changes are recorded in earnings as an offset to the changes in fair value of the exposure being hedged or deferred in accumulated other comprehensive income and recognized in earnings as hedged transactions occur. Amounts recorded in earnings are included in revenue, purchased power or other, net on the consolidated statements of income.

Revenues and expenses on contracts that qualify as normal purchases or normal sales are recognized when the underlying physical transaction is completed. “Normal” purchases and sales are

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(Dollars in millions, except per share data unless otherwise noted)

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. 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. If it was determined that a transaction designated as a “normal” purchases or a “normal” sale no longer met the scope exceptions, the fair value of the related contract would be recorded on the balance sheet and immediately recognized through earnings.

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, and is designated and qualifies as, a fair-value hedge, are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. Changes in the fair value of a derivative that is highly effective, and is designated and qualifies as, a cash-flow hedge are deferred in accumulated other comprehensive income and are recognized in earnings as the hedged transactions occur. Any ineffectiveness is recognized in earnings immediately. On an ongoing basis, Exelon assesses the hedge effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that the derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively.

Generation enters into contracts to buy and sell energy for trading purposes subject to Exelon’s Risk Management Policy. 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.

Severance Benefits

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.” Amounts associated with severance benefits that are considered probable and can be reasonably estimated are accrued. See Note 9—Severance Accounting for further discussion of Exelon’s accounting for severance benefits.

Retirement Benefits

Exelon’s defined benefit pension plans and postretirement welfare benefit plans are accounted for in accordance with SFAS No. 87, “Employer’s Accounting for Pensions” (SFAS No. 87), SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” (SFAS No. 106) and FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2), and are disclosed in accordance with SFAS No. 132-R, “Employers’ Disclosures about Pensions and Other

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(Dollars in millions, except per share data unless otherwise noted)

Postretirement Benefits—an Amendment of FASB Statements No. 87, 88, and 106” (revised 2003) (SFAS No. 132-R). See Note 15—Retirement Benefits for further discussion of Exelon’s accounting for retirement benefits in accordance with SFAS No. 87 and SFAS No. 106 and disclosures pursuant to SFAS No. 132-R.

FSP FAS 106-2.Through its postretirement benefit plans, Exelon provides retirees with prescription drug coverage. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Prescription Drug Act) was enacted on December 8, 2003. 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. Management believes the prescription drug benefit provided under Exelon’s postretirement benefit plans is at least actuarially equivalent to the Medicare prescription drug benefit. In response to the enactment of the Prescription Drug Act, in May 2004, the FASB issued FSP FAS 106-2, which provided transition guidance for accounting for the effects of the Prescription Drug Act and superseded FSP FAS 106-1, which had been issued in January 2004. FSP FAS 106-1 permitted 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 made the one-time election allowed by FSP FAS 106-1 during the first quarter of 2004.

During the second quarter of 2004, Exelon early adopted the provisions of FSP FAS 106-2, resulting in a remeasurement of its postretirement benefit plans’ assets and accumulated postretirement benefit obligations (APBO) as of December 31, 2003. Upon adoption, the effect of the subsidy on benefits attributable to past service was accounted for as an actuarial experience gain, resulting in a decrease of the APBO of approximately $186 million. The annualized reduction in the net periodic postretirement benefit cost was approximately $40 million and $33 million in 2005 and 2004, respectively, compared to the annual cost calculated without considering the effects of the Prescription Drug Act. The effect of the subsidy on the components of net periodic postretirement benefit cost for 2005 and 2004 included in the consolidated financial statements and Note 15—Retirement Benefits was as follows:

	2005		2004
Amortization of the actuarial experience loss	$	18	$	15
Reduction in current period service cost		8		6
Reduction in interest cost on the APBO		14		12

Treasury Stock

Treasury shares are recorded at cost. Any shares of common stock repurchased are held as treasury shares unless cancelled or reissued.

Foreign Currency Translation

The financial statements of Exelon’s foreign subsidiaries were prepared in their respective local currencies and translated into U.S. dollars based on the current exchange rates at the end of the periods for the Consolidated Balance Sheets and on weighted-average rates for the periods for the Consolidated Statements of Income. Foreign currency translation adjustments, net of deferred income tax benefits, are reflected as a component of other comprehensive income on the Consolidated Statements of Comprehensive Income and, accordingly, have no effect on net income.

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(Dollars in millions, except per share data unless otherwise noted)

New Accounting Pronouncements

EITF 03-1.In March 2004, the EITF reached a consensus on and the FASB ratified EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (EITF 03-1). EITF 03-1 provides guidance on recognizing other-than-temporary impairments of investment securities. Exelon has adopted the disclosure requirements of EITF 03-1 for investments accounted for under FASB Statement No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS No. 115). On September 30, 2004, the FASB issued FSP EITF 03-1-1, “Effective Date of Paragraphs 10-20 of EITF Issue No. 03-1, ‘The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments,’” which delayed the effective date of the application guidance on impairment of securities included within EITF 03-1. The FASB, at its June 29, 2005 Board meeting, withdrew its guidance on when an impairment is other than temporary. However, EITF 03-1’s provisions regarding the measurement, disclosure and post-impairment accounting guidance of debt securities, as well as the identification of impaired cost method investments remain intact. Additionally, the existing guidance under SFAS No. 115 remains in effect.

SFAS No. 151. In November 2004, the FASB issued FASB Statement No. 151, “Inventory Costs—an amendment of ARB No. 43, Chapter 4” (SFAS No. 151), which is the result of its efforts to converge U.S. accounting standards for inventories with International Accounting Standards. SFAS No. 151 requires abnormal amounts of idle facility expense, freight, handling costs and wasted material or spoilage to be recognized as current-period charges. It also requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS No. 151 will be effective for inventory costs incurred beginning January 1, 2006. The adoption of this standard is not expected to have a material impact on Exelon.

SFAS No. 123-R.In December 2004, the FASB issued FASB Statement No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123-R). SFAS No. 123-R replaces SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123) and supersedes Accounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees” (APB No. 25). SFAS No. 123-R requires that compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. Exelon will no longer be permitted to follow the intrinsic value accounting method of APB No. 25. APB No. 25 resulted in no expense being recorded for stock option grants for which the strike price was equal to the fair value of the underlying stock on the date of grant, which has been the situation for Exelon for all years prior to 2006. SFAS No. 123-R will be effective for Exelon in the first quarter of 2006 and will apply to all of Exelon’s outstanding unvested share-based payment awards as of January 1, 2006 and all prospective awards using the modified prospective transition method without restatement of prior periods.

In March 2005, the SEC issued Staff Accounting Bulletin (SAB) No. 107 which expressed the views of the SEC regarding the interaction between SFAS No. 123-R and certain SEC rules and regulations. SAB No. 107 provides guidance related to the valuation of share-based payment arrangements for public companies, including assumptions such as expected volatility and expected term.

Exelon will determine the fair value of share-based equity or liability instruments issued to employees subsequent to January 1, 2006 using the Black-Scholes-Merton option-pricing model for stock options and a Monte Carlo simulation model for performance shares subject to market conditions

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(Dollars in millions, except per share data unless otherwise noted)

to calculate the amount of compensation cost that must be recognized in the financial statements as a result of adopting SFAS No. 123-R. The dividend yield, volatility and risk-free interest rate assumptions will be estimated in a manner consistent with the methodology currently used to estimate the assumptions in 2005 disclosed in Note 18—Common Stock. Exelon estimates that the 2006 impact of adopting SFAS No. 123-R will be approximately $45 million to $65 million before income taxes and the effects of capitalization, which approximates the annual 2005, 2004 and 2003 pro forma stock-based compensation expense amounts shown in the table below. The actual cost will differ from this range due to changes in assumptions. This estimated range primarily reflects the impact of expensing stock options for the first time and accelerating the expense for new grants of stock-based awards.

Exelon currently accounts for its stock-based compensation plans under the intrinsic method prescribed by APB No. 25 and related interpretations and follows the disclosure requirements of SFAS No. 123 and SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123.” Accordingly, compensation expense related to stock options recognized within the Consolidated Statements of Income was insignificant in 2005, 2004 and 2003. Expense recognized related to other stock-based compensation plans is further described in Note 18—Common Stock. The tables below show the effect on Exelon’s net income and earnings per share had Exelon elected to account for all of its stock-based compensation plans using the fair-value method under SFAS No. 123 in 2005, 2004 and 2003:

	2005			2004			2003
Net income—as reported	$	923		$	1,864		$	905
Add: Stock-based compensation expense included in reported net income, net of income taxes		34			39			19
Deduct: Total stock-based compensation expense determined under fair-value method for all awards, net of income taxes(a)		(48	)		(60	)		(39	)
Pro forma net income	$	909		$	1,843		$	885
Earnings per share:
Basic—as reported	$	1.38		$	2.82		$	1.39
Basic—pro forma	$	1.36		$	2.79		$	1.36
Diluted—as reported	$	1.36		$	2.78		$	1.38
Diluted—pro forma	$	1.35		$	2.75		$	1.35

(a) The fair value of options granted was estimated using a Black-Scholes-Merton option pricing model.

Exelon recognizes the compensation cost of stock-based awards issued to retirement eligible employees that fully vest upon an employee’s retirement over the nominal vesting period of performance and recognizes any remaining compensation cost at the date of retirement. Upon the adoption of SFAS No. 123-R, Exelon will be required to recognize the entire compensation cost at the grant date of new stock-based awards in which retirement-eligible employees are fully vested upon issuance (the non-substantive vesting approach). There would have not have been a material impact to Exelon’s stock-based compensation expense had Exelon accounted for its stock-based awards in which retirement-eligible employees are fully vested upon issuance using the non-substantive vesting approach.

SFAS No. 153. In December 2004, the FASB issued FASB Statement No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, ‘Accounting for Nonmonetary

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(Dollars in millions, except per share data unless otherwise noted)

Transactions’” (SFAS No. 153). Previously, APB Opinion No. 29 had required that the accounting for an exchange of a productive asset for a similar productive asset or an equivalent interest in the same or similar productive asset should be based on the recorded amount of the asset relinquished. The amendments made by SFAS No. 153 are based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, the amendments eliminate the narrow exception for nonmonetary exchanges of similar productive assets and replace it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance, in essence increasing the number of exchanges that will be fair valued in the future. SFAS No. 153 was effective in the third quarter of 2005. The provisions of SFAS No. 153 are applied prospectively. The adoption of this standard did not have a material impact on Exelon’s financial condition or results of operations in the third or fourth quarter of 2005.

FIN 47.In March 2005, the FASB issued FIN 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47) which clarifies that the term “conditional asset retirement obligation” as used in FASB Statement No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143), refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 was effective for Exelon as of December 31, 2005. See Note 14—Conditional Asset Retirement Obligations for further information.

SFAS No. 154.In May 2005, the FASB issued FASB Statement No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS No. 154). Previously, APB No. 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements” required the inclusion of the cumulative effect of changes in accounting principle in net income of the period of the change. SFAS No. 154 requires companies to recognize a change in accounting principle, including a change required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements. Exelon will assess the impact of a retrospective application of a change in accounting principle in accordance with SFAS No. 154 when such a change arises after the effective date of January 1, 2006.

Cumulative Effect of Changes in Accounting Principles

FIN 47.During 2005, Exelon recorded a charge of $42 million (net of income taxes of $27 million) as a cumulative effect of a change in accounting principle pursuant to the adoption of FIN 47. See discussion of the adoption of FIN 47 above.

EITF 03-16.In March 2004, the EITF reached a consensus on and the FASB ratified EITF Issue No. 03-16, “Accounting for Investments in Limited Liability Companies” (EITF 03-16). The EITF concluded that if investors in a limited liability company have specific ownership accounts, they should follow the guidance prescribed in Statement of Position 78-9, “Accounting for Investments in Real Estate Ventures,” and EITF Topic No. D-46, “Accounting for Limited Partnership Investments.” Otherwise, investors should follow the significant influence model prescribed in Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” EITF 03-16 was effective for Exelon and its subsidiaries during the third quarter of 2004. Exelon recorded a charge of $9 million (net of an income tax benefit of $5 million) as a cumulative effect of a change in accounting principle in connection with its adoption of EITF 03-16 as of July 1, 2004. This charge related to certain investments in limited liability partnerships held by Enterprises.

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(Dollars in millions, except per share data unless otherwise noted)

FIN 46-R.See discussion of the adoption of FIN 46-R within the “Variable Interest Entities” discussion above.

SFAS No. 143.SFAS No. 143 provides accounting guidance for retirement obligations (whether statutory, contractual or as a result of principles of promissory estoppel) associated with tangible long-lived assets. Exelon adopted SFAS No. 143 as of January 1, 2003 and recorded income of $112 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 components of the cumulative effect of a change in accounting principle, net of income taxes, were as follows:

Generation (net of income taxes of $52)	$	80
Generation’s investments in AmerGen and Sithe (net of income taxes of $18)		28
ComEd (net of income taxes of $0)		5
Enterprises (net of income taxes of $(1))		(1	)
Total	$	112

The following tables set forth Exelon’s net income and basic and diluted earnings per common share for the years ended December 31, 2005, 2004 and 2003, adjusted as if SFAS No. 143, FIN 46-R, EITF 03-16, and FIN 47 had been applied during those periods. SFAS No. 143, FIN 46-R, EITF 03-16 and FIN 47 had adoption dates of January 1, 2003, March 31, 2004, July 1, 2004, and December 31, 2005, respectively.

	2005			2004			2003
Reported income before cumulative effect of changes in accounting principles	$	965		$	1,841		$	793
Pro forma earnings effects (net of income taxes):
FIN 47		(5	)		(4	)		(4	)
EITF 03-16		—			(1	)		—
FIN 46-R		—			—			32
Pro forma income before cumulative effect of changes in accounting principles	$	960		$	1,836		$	821
Reported net income	$	923		$	1,864		$	905
Pro forma earnings effects (net of income taxes):
FIN 47		(5	)		(4	)		(4	)
EITF 03-16		—			(1	)		—
FIN 46-R		—			—			32
Reported cumulative effects of changes in accounting principles:
FIN 47		42			—			—
EITF 03-16		—			9			—
FIN 46-R		—			(32	)		—
SFAS No. 143		—			—			(112	)
Pro forma net income	$	960		$	1,836		$	821

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(Dollars in millions, except per share data unless otherwise noted)

	2005		2004		2003
Basic earnings per common share:
Reported income before cumulative effect of changes in accounting principles	$	1.44	$	2.79	$	1.22
Pro forma income before cumulative effect of changes in accounting principles	$	1.43	$	2.78	$	1.26
Reported net income	$	1.38	$	2.82	$	1.39
Pro forma net income	$	1.43	$	2.78	$	1.26
	2005		2004		2003
Diluted earnings per common share:
Reported income before cumulative effect of changes in accounting principles	$	1.42	$	2.75	$	1.21
Pro forma income before cumulative effect of changes in accounting principles	$	1.42	$	2.74	$	1.25
Reported net income	$	1.36	$	2.78	$	1.38
Pro forma net income	$	1.42	$	2.74	$	1.25

2. Discontinued Operations

On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. In addition, during 2003 and 2004, Exelon sold or wound down substantially all components of Enterprises, and during 2004 Generation sold or wound down substantially all components of AllEnergy Gas & Electric Marketing LLC (AllEnergy), a business within Exelon Energy. As a result, the results of operations and any gain or loss on the sale of these entities are presented as discontinued operations in 2005 within Exelon’s Consolidated Statements of Income. In addition, the results of operations of these entities have been presented as discontinued operations in 2004 and 2003 for comparative purposes. Results related to these entities were as follows:

2005	Sithe (a)		Enterprises (b)			AllEnergy		Total
Total operating revenues	$	30	$	18		$	—	$	48
Operating income (loss)		5		(8	)		1		(2	)
Income (loss) before income taxes and minority interest		23		(7	)		1		17

(a) Sithe was sold on January 31, 2005. Accordingly, results only include one month of operations. See Note 3—Acquisitions and Dispositions for further information regarding the sale of Sithe.

(b) Excludes certain investments.

2004	Sithe (a)			Enterprises (b)			AllEnergy			Total
Total operating revenues	$	227		$	154		$	8		$	389
Operating loss		(7	)		(57	)		(2	)		(66	)
Loss before income taxes and minority interest		(58	)		(5	)		(2	)		(65	)

(a) Includes Sithe’s results of operations from April 1, 2004 through December 31, 2004. See Note 3—Acquisitions and Dispositions for further information regarding the sale of Sithe.

(b) Excludes certain investments.

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(Dollars in millions, except per share data unless otherwise noted)

2003	Sithe (a)		Enterprises (b)			AllEnergy			Total
Total operating revenues	$	—	$	533		$	174		$	707
Operating loss		—		(97	)		(35	)		(132	)
Loss before income taxes and minority interest		—		(123	)		(35	)		(158	)

(a) Sithe’s results of operations for the year 2003 were included as an unconsolidated equity method investment prior to its consolidation on March 31, 2004. See Note 3—Acquisitions and Dispositions for further information regarding the sale of Sithe.

(b) Excludes certain investments.

As discussed in Note 3—Acquisitions and Dispositions, Exelon sold the electric construction and services, underground and telecom businesses of InfraSource in 2003 and Generation sold its indirect wholly owned subsidiary Boston Generating in 2004. Because Exelon maintains significant continuing involvement with these entities, due to various contractual arrangements described in Note 3—Acquisitions and Dispositions, they have not been classified as discontinued operations within Exelon’s Consolidated Statements of Income.

3. Acquisitions and Dispositions

Proposed Merger with PSEG

On December 20, 2004, Exelon entered into an Agreement and Plan of Merger (Merger Agreement) with Public Service Enterprise Group Incorporated (PSEG), an exempt public utility holding company primarily located and serving customers in New Jersey, whereby PSEG will be merged with and into Exelon (Merger). PSEG shareholders approved the Merger on July 19, 2005. Exelon shareholders approved the issuance of Exelon shares pursuant to the Merger on July 22, 2005. Under the Merger Agreement, each share of PSEG common stock will be converted into 1.225 shares of Exelon common stock. The Merger Agreement contains certain termination rights for both Exelon and PSEG, and further provides that, upon termination of the Merger Agreement under specified circumstances, (i) Exelon may be required to pay PSEG a termination fee of $400 million plus PSEG’s transaction expenses up to $40 million or (ii) PSEG may be required to pay Exelon a termination fee of $400 million plus Exelon’s transaction expenses up to $40 million.

In 2005, Exelon filed petitions or applications for approval or review of the Merger, or approval of matters related to the Merger, with various federal and state regulatory authorities, including the FERC under the Federal Power Act, the United States Department of Justice under the Hart Scott Rodino Antitrust Improvements Act of 1976, the PAPUC, the New Jersey Board of Public Utilities (NJBPU), the United States Nuclear Regulatory Commission (NRC), the New York Public Service Commission, the Connecticut Siting Council, the New Jersey Department of Environmental Protection (NJDEP) and the Public Utility Commission of Texas under the Texas Public Utility Regulatory Act. Various other state and Federal agencies and agencies of foreign countries have a role in reviewing various aspects of the transaction. ComEd filed a notice of the Merger with the Illinois Commerce Commission (ICC) and the ICC’s general counsel confirmed that its formal approval of the Merger is not required.

As of February 14, 2006, all material regulatory approvals or reviews necessary to complete the Merger have been completed with the exception of the approval from the NJBPU and the NRC and the review by the United States Department of Justice.

The FERC approved the Merger on June 30, 2005. Exelon and PSEG proposed in their application with the FERC, and FERC approved, a market concentration mitigation plan involving the

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Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

divestiture of 4,000 MW of coal, mid-merit (or intermediate) and peaking generation in the PJM region and the ongoing auction of 2,600 MW of nuclear output and the interim mitigation of fossil generation pending divestiture. Exelon and PSEG also proposed to invest a total of $25 million in transmission improvements, which was included in the proposal that was accepted by FERC. The ultimate outcome of the market concentration mitigation is dependent upon various factors, including the market conditions and buyer interest at the time the generating units and the nuclear output are offered for sale. The results of these activities, therefore, are not assured, and could have a material impact on the results of operations and cash flows of Exelon and Generation if the sales price for the divested assets is different from management’s expectations. The FERC considered petitions for rehearing with respect to the order approving the Merger and affirmed its order on December 15, 2005. On January 6 and January 13, 2006, Philadelphia Gas Works/City of Philadelphia and subsidiaries of PPL Corporation, parties to the FERC proceeding, filed petitions for review of the FERC order in the United States Court of Appeals for the District of Columbia.

On January 27, 2006, the PAPUC approved the Merger and a partial settlement regarding PECO’s distribution and transmission rates through 2010 and other financial commitments of PECO related to the Merger. The settlement reflected the conclusion of a process involving the majority of PECO customer groups during which PECO’s cost data, return on equity and estimated Merger synergies were reviewed. The provisions of the PAPUC order and partial settlement are contingent upon the completion of the Merger. The PAPUC order and partial settlement require PECO to implement rate reductions aggregating $120 million during a four-year period and to cap its rates through the end of 2010. During the rate cap period, the PAPUC retains the right to lower PECO’s rates if they are found to be excessive, and PECO retains the right to seek rate increases if certain events (such as 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) occur. The partial settlement also provides substantial funding for alternative energy and environmental projects, economic development, and expanded outreach and assistance for low-income customers. PECO also made commitments for enhanced customer service and reliability, commitments for charitable giving and employment, and a pledge to maintain its Philadelphia headquarters for a period of time. The total of these funding commitments is approximately $44 million, of which $30 million will be expensed at the time the Merger is completed. By separate motion, the PAPUC also indicated its intent to initiate a separate investigation, to which PECO had agreed in the partial settlement, to examine issues related to a potential combination of Philadelphia Gas Works, which provides gas distribution service in the City of Philadelphia, into Exelon’s gas distribution businesses. This investigation will commence no earlier than 30 days after the close of the Merger. The outcome of this potential examination is uncertain. However, Exelon does not believe that the PAPUC has the authority to compel such a transaction if the two parties do not agree to terms through arms length negotiations.

On September 30, 2005, the administrative law judge in the proceeding before the NJBPU amended a prior prehearing order to modify the timetable for the regulatory approval process in New Jersey. The revised procedural schedule for the Merger review called for testimony to be filed from mid-November to mid-December and for hearings in January 2006. Under that revised schedule, the initial decision of the administrative law judge was expected in March 2006 and a final order from the full NJBPU was expected in May 2006. On January 25, 2006, the schedule for hearings was extended through March 27, 2006. On February 8, 2006, the administrative law judge approved a revised schedule calling for additional hearings on March 13, 14, 24 and 27, 2006. The dates originally scheduled for the administrative law judge’s initial decision and the final order of the full NJBPU will also be extended but no firm dates have been set. Settlement discussions in New Jersey began in December 2005 and are expected to resume after completion of hearings before the NJBPU. Exelon

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

will attempt to reach a settlement that satisfactorily resolves issues and allows the Merger to close in the second quarter of 2006. However, in the absence of an earlier settlement, Exelon expects that the closing of the Merger will occur in the third quarter of 2006.

Various governmental, consumer and other parties have intervened in the proceedings before the NJBPU and other regulatory bodies. To facilitate approval of the Merger, Exelon may negotiate with these parties and may enter into settlement agreements. Orders resulting from the proceedings before the NJBPU and other regulatory bodies and settlements in connection with the proceedings could, for example, affect the extent to which Exelon and its subsidiaries may benefit from expected synergies following the Merger and could be materially different from what the Registrants expect in this and other respects, and could have a material impact on the financial condition, results of operations and cash flows of the Registrants if the Merger is completed.

The regulatory and political developments in Illinois (see Note 4—Regulatory Issues) may also have an effect on the settlement discussions and proceedings before the NJBPU could delay that regulatory approval. Some possible outcomes of the developments in Illinois could also have an effect on the timing or closing conditions to the Merger.

Exelon has capitalized certain external costs associated with the Merger since the execution of the Merger Agreement on December 20, 2004. Total capitalized costs of $46 million and $10 million are included in deferred debits and other assets on Exelon’s Consolidated Balance Sheets as of December 31, 2005 and December 31, 2004, respectively.

Disposition of Enterprises Entities

Exelon Thermal Holdings, Inc. On June 30, 2004, Enterprises sold the Chicago businesses of Exelon Thermal Holdings, Inc. (Thermal) for net cash proceeds of $134 million and expected proceeds of $2 million from a working capital settlement, resulting in a pre-tax gain of $45 million. Prior to closing, Enterprises repaid $37 million of related debt, resulting in prepayment penalties of $9 million.

On September 29, 2004, Enterprises sold ETT Nevada, Inc., the holding company for its investment in Northwind Aladdin, LLC, for a net cash outflow of $1 million, resulting in a pre-tax loss of $3 million.

On October 28, 2004, Northwind Windsor, of which Enterprises owned a 50% interest, sold substantially all of its assets, providing Enterprises with cash proceeds of $8 million, resulting in a pre-tax gain of $2 million.

Exelon Services, Inc. During 2004, Enterprises disposed of or wound down all of the operating businesses of Exelon Services, Inc. (Exelon Services), including Exelon Solutions, the mechanical services businesses and the Integrated Technology Group. Total expected proceeds and the net pre-tax gain on sale recorded during 2004 related to these dispositions were $61 million and $9 million, respectively. Pre-tax impairment charges of $5 million and $14 million related to Exelon Services’ tangible assets were recorded in 2004 and 2003, respectively. Exelon Services also recorded a pre-tax charge of $24 million in 2003 to impair its remaining goodwill. As of December 31, 2005 and 2004, Exelon Services had remaining assets of $51 million and $74 million, respectively, and liabilities of $5 million and $22 million, respectively, which primarily consisted of tax assets, affiliate receivables and payables, and sales proceeds to be collected.

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(Dollars in millions, except per share data unless otherwise noted)

PECO TelCove. On June 30, 2004, Enterprises sold its investment in PECO TelCove, a communications joint venture, along with certain telecommunications assets, for proceeds of $49 million. A pre-tax gain of $9 million was recorded in other income and deductions on Exelon’s Consolidated Statements of Income. An impairment charge of $5 million (before income taxes) related to the telecommunications assets had been recorded in the fourth quarter of 2003.

InfraSource.On September 24, 2003, Enterprises sold the electric construction and services, underground and telecom businesses of InfraSource. Cash proceeds to Enterprises from the sale were approximately $175 million, net of transaction costs and cash transferred to the buyer upon sale, plus a $30 million subordinated note receivable maturing in 2011. At the time of closing, the present value of the note receivable was approximately $12 million. The note was collected in full during the second quarter of 2004, resulting in pre-tax income of $18 million. In connection with the transaction, Enterprises entered into an agreement that may result in certain payments to InfraSource if the amount of services Exelon purchases from InfraSource during the period from closing through 2006 is below specified thresholds. Due to Exelon’s ongoing involvement with InfraSource through this agreement and in accordance with SFAS No. 144 and EITF 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report a Discontinued Operation,” the results of InfraSource have not been classified as a discontinued operation within Exelon’s Consolidated Statements of Income.

In connection with the agreement to sell InfraSource, Enterprises recorded an impairment charge during the second quarter of 2003 of approximately $48 million (before income taxes and minority interest) pursuant to SFAS No. 142 related to the goodwill recorded within the InfraSource reporting unit. Management of Enterprises primarily considered the negotiated sales price and the estimated book value of InfraSource at the time of the closing of the sale in determining the amount of the goodwill impairment charge. In connection with the closing of the sale in the third quarter of 2003, Enterprises recorded a pre-tax gain of $44 million, primarily due to the book value of InfraSource at the date of closing being lower than estimated in the second quarter of 2003. The net impact of the goodwill impairment in the second quarter and the gain recorded in the third quarter was a pre-tax loss and minority interest of $4 million for the year ended December 31, 2003. The net impact was recorded as an operating and maintenance expense within Exelon’s Consolidated Statements of Income.

Sale of Investments. On December 1, 2004, Enterprises sold its limited partnership interest in EnerTech Capital Partners II, L.P. and its limited liability company interests in Kinetic Ventures I, LLC and Kinetic Ventures II, LLC for $8 million in cash and the assumption by the buyers of approximately $10 million in unfunded capital commitments. Prior to the sale, in 2004, these investments were written down to their expected sales price, resulting in pre-tax impairment charges totaling $18 million. As such, there was no net gain or loss recorded associated with the sale.

The results of Thermal and Exelon Services have been included in discontinued operations within Exelon’s Consolidated Statements of Income. See Note 2—Discontinued Operations for additional information.

Investments in Synthetic Fuel-Producing Facilities

In November 2003, Exelon purchased interests in two synthetic fuel-producing facilities. The purchase price for these facilities included a combination of cash, notes payable and contingent consideration dependent upon the production level of the facilities. The notes payable recorded for the

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(Dollars in millions, except per share data unless otherwise noted)

purchase of the facilities were $238 million. Exelon’s right to acquire a fixed amount of tax credits generated by the facilities was recorded as an intangible asset which is amortized as the tax credits are earned.

In July 2004, Exelon purchased an interest in a limited partnership that indirectly owns four synthetic fuel-producing facilities. Exelon’s purchase price for these facilities included a combination of a note payable and contingent consideration dependent upon the production levels of the facilities. The note payable recorded for the purchase of the facilities was $22 million. Exelon’s right to acquire a fixed amount of tax credits generated by the facilities was recorded as an intangible asset which is amortized as these tax credits are earned.

See Note 12—Income Taxes for additional information regarding Exelon’s investments in synthetic fuel-producing facilities.

Investments in Affordable Housing

On October 15, 2004 and November 12, 2004, Exelon sold investments in affordable housing for total proceeds of $78 million and recognized a net gain on sale of $4 million before income taxes.

Acquisition and Disposition of Sithe

Sithe is primarily engaged in the ownership and operation of electric wholesale generating facilities in North America. At December 31, 2004, Sithe operated nine power units with total average net capacity of 1,323 MWs. Described below is a series of transactions in 2004 and 2003 involving Generation’s investment in Sithe that ultimately resulted in the sale of Generation’s ownership interest in Sithe to a third party on January 31, 2005.

On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. Specifically, subsidiaries of Generation closed on the acquisition of Reservoir Capital Group’s (Reservoir) 50% interest in Sithe and the sale of 100% of Sithe to Dynegy, Inc. (Dynegy). Prior to closing on the sale to Dynegy, subsidiaries of Generation received approximately $65 million in cash distributions from Sithe. As a result of the sale, Exelon deconsolidated approximately $820 million of debt from its balance sheets and was no longer required to provide $125 million of credit support to Dynegy on behalf of Sithe. Dynegy acquired $32 million of cash as part of the sale of Sithe. Additionally, Exelon recorded $55 million of liabilities related to certain indemnifications provided to Dynegy and other guarantees directly resulting from the transaction. These liabilities were taken into account in the determination of the net gain on the sale of $24 million (before income taxes). As of December 31, 2005, Exelon’s accrued liabilities related with these indemnifications and guarantees were $46 million. The net decrease was a result of the unwinding of certain guarantees and tax indemnifications that were associated with the sale transaction.

Generation issued certain guarantees associated with income tax indemnifications to Dynegy in connection with the sale that were valued at approximately $8 million, of which $3 million has been unwound as of December 31, 2005. These guarantees are being accounted for under the provisions of FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others” (FIN 45). The exposures covered by these indemnities are anticipated to expire in 2006 and beyond. The estimated maximum possible exposure to Exelon related to the guarantees provided as part of the sales transaction to Dynegy is approximately $175 million at December 31, 2005.

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Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Exelon’s Consolidated Statements of Income included the following financial results related to Sithe:

	2005 (a)		2004 (b)
Operating revenues	$	30	$	248
Operating income		5		1
Net income (loss)(c)		18		(27	)

(a) Sithe was sold on January 31, 2005. Accordingly, results include only one month of operations.

(b) Results include Exelon’s equity-method losses from Sithe prior to its consolidation on March 31, 2004, as well as transmission congestion contract (TCC) revenues for 2004, and are not included in the discontinued operations of Sithe (see Note 2—Discontinued Operations for further information regarding the disposal of Sithe). These equity-method losses and TCC revenues are presented within income from continuing operations on the Consolidated Statements of Income.

(c) Net income for 2005 included a pre-tax gain on sale of Sithe of $24 million.

Exelon’s Consolidated Balance Sheets as of December 31, 2004 included current assets, noncurrent assets, current liabilities and noncurrent liabilities, which were disposed of upon the sale of Sithe on January 31, 2005, of $57 million, $885 million, $106 million and $825 million, respectively.

Exercise of Call Option and Subsequent Agreement to Sell.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 (Generation owned 49.9% prior to November 25, 2003). See below for further details regarding these 2003 transactions.

Both Generation’s and Reservoir’s 50% interests in Sithe were subject to put and call options. On September 29, 2004, Generation exercised its call option and entered into an agreement to acquire Reservoir’s 50% interest in Sithe for $97 million. On November 1, 2004, Generation entered into an agreement to sell Sithe to Dynegy Inc. (Dynegy) for $135 million in cash. On January 31, 2005, Generation completed the closing of the call exercise and the sale of the resulting 100% interest in Sithe. The sale did not include Sithe International, Inc., which was sold to a subsidiary of Generation in a separate transaction described below.

Acquisition of Sithe International, Inc.Sithe International, through its subsidiaries, has 49.5% interests in two Mexican business trusts that own the TEG and TEP power stations, two 230 MW petcoke-fired generating facilities in Tamuín, Mexico that commenced commercial operations in the second quarter of 2004. On October 13, 2004, Sithe transferred all of the shares of Sithe International, Inc. and its subsidiaries to a subsidiary of Generation in exchange for cancellation of a $92 million note, which is eliminated as part of the consolidation of Sithe. Effective January 26, 2005, Sithe International’s name was changed to Tamuin International Inc.

2003 Transactions. 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. 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 49.9% interest on November 24, 2003 and the remaining 50.1% interest on May 27, 2004 for separate consideration) for $178 million.

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Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Following the sales of the above entities, Generation transferred its wholly owned subsidiary that held the Sithe investment to a newly formed holding company, EXRES SHC, Inc. 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.

Guarantees.In connection with the 2003 transactions, Generation recorded obligations related to $39 million of guarantees in accordance with FIN 45. These guarantees were issued to protect Reservoir from credit exposure of certain counterparties 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. These guarantees were reversed upon the consolidation of Sithe in accordance with FIN 45 as this liability was associated with guarantees for the performance of a consolidated entity. The consolidation of Sithe in accordance with FIN 46-R resulted in Exelon recording income of $32 million (net of income taxes), which included the reversal of the aforementioned guarantees, as a cumulative effect of a change in accounting principle during the first quarter of 2004.

Accounting Prior to the Consolidation of Sithe on March 31, 2004.Generation had accounted for the investment in Sithe as an unconsolidated equity method investment prior to its consolidation on March 31, 2004 pursuant to FIN 46-R. See Note 1—Significant Accounting Policies for further discussion. In 2003, Exelon 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.

The book value of Generation’s investment in Sithe immediately prior to its consolidation on March 31, 2004 was $49 million. For the year ended December 31, 2004, Exelon recorded $2 million of equity method losses from Sithe prior to its consolidation. For the year ended December 31, 2003 and 2002, Exelon recorded $2 million and $23 million of equity method income, respectively, related to its investment in Sithe.

Consolidation of Sithe as of March 31, 2004.As a result of the 2003 transactions referred to above, the consolidation of Sithe at March 31, 2004 was accounted for as a step acquisition pursuant to purchase accounting policies. Under the provisions of FIN 46-R, the operating results of Sithe were included in Exelon’s results of operations beginning April 1, 2004.

Intangible Assets.Sithe had entered into a tolling arrangement (Tolling Agreement) with Dynegy Power Marketing and its affiliates with respect to Sithe’s Independence Station. The Tolling Agreement commenced on July 1, 2001 and runs through 2014. Additionally, Sithe entered into an energy purchase agreement (Energy Purchase Agreement) with a counterparty relating to the Independence Station, which continues through 2014. As a result of the acquisition accounting described above, values were assigned to the Tolling Agreement and the Energy Purchase Agreement of approximately $73 million and $384 million, respectively, which were recorded as intangible assets on Exelon’s

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Exelon Corporation and Subsidiary Companies

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(Dollars in millions, except per share data unless otherwise noted)

Consolidated Balance Sheets in deferred debits and other assets. These amounts were determined based on fair value techniques utilizing the contract terms and various other estimates including forward power prices, discount rates and option pricing models.

Prior to the sale of Sithe, the intangible assets representing the Tolling Agreement and the Energy Purchase Agreement were being amortized on a straight-line basis over the lives of the associated agreements. See Note 8—Intangible Assets for further information regarding Exelon’s intangible assets.

Long-Term Debt and Letters of Credit.Substantially all of Sithe’s property, plant and equipment and project agreements secured Sithe’s outstanding long-term debt, which consisted primarily of project debt. During 2003, Sithe entered into an agreement with Exelon and Generation under which Exelon obtained letters of credit to support contractual obligations of Sithe and its subsidiaries. As of December 31, 2004, Exelon had obtained $111 million of letters of credit in support of Sithe’s obligations. As a result of the sale of Sithe on January 31, 2005, Generation was no longer required to provide credit support, which included letters of credit.

Sale of Ownership Interest in Boston Generating, LLC

On May 25, 2004, Generation completed the sale, transfer and assignment of ownership of its indirect wholly owned subsidiary Boston Generating, which owns the companies that own Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities, to a special purpose entity owned by the lenders under Boston Generating’s $1.25 billion credit facility (Boston Generating Credit Facility).

The sale was pursuant to a settlement agreement reached with Boston Generating’s lenders on February 23, 2004. The FERC approved the sale of Boston Generating on May 25, 2004. Responsibility for plant operations and power marketing activities were transferred to the lenders’ special purpose entity on September 1, 2004.

In connection with the settlement reached on February 23, 2004, Exelon, Generation, the lenders and Raytheon Company (Raytheon), the guarantor of the obligations of the turnkey contractor under the projects’ engineering, procurement and construction agreements, entered into a global settlement of all disputes relating to the construction of the Mystic 8 and 9 and Fore River generating facilities.

In connection with the decision to transition out of Boston Generating and the generating units, Exelon recorded during the third quarter of 2003 an impairment charge of long-lived assets pursuant to SFAS No. 144 of $945 million ($573 million net of income taxes) in operating expenses within its Consolidated Statements of Income.

Boston Generating was reported in the Generation segment of Exelon’s consolidated financial statements prior to its sale. At the date of the sale, Boston Generating had approximately $1.2 billion in assets, primarily consisting of property, plant and equipment, and approximately $1.3 billion of liabilities of which approximately $1.0 billion was debt outstanding under the Boston Generating Credit Facility. As of the date of transfer, these amounts were eliminated from Exelon’s Consolidated Balance Sheets. As a result of Boston Generating’s liabilities being greater than its assets at the time of the sale, transfer and assignment of ownership, Exelon recorded a gain of $85 million ($52 million net of income taxes) in other income and deductions within the Consolidated Statements of Income in the second quarter of 2004.

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Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

In connection with the sale, Exelon recorded a liability associated with an existing guarantee by its subsidiary Exelon New England Holdings, LLC (Exelon New England) of fuel purchase obligations of Boston Generating. At December 31, 2005, the liability associated with this guarantee was $14 million. Due to the existence of this guarantee and in accordance with SFAS No. 144 and EITF 03-13, Generation determined that it had retained risk and continuing involvement associated with the operations of Boston Generating and, as a result, the results of Boston Generating have not been classified as a discontinued operation within Exelon’s Consolidated Statements of Income. See Note 20—Commitments and Contingencies for further information regarding the guarantee.

Exelon’s Consolidated Statements of Income include the following results related to Boston Generating:

	2004			2003
Operating revenues	$	248		$	618
Operating loss(a)		(49	)		(954	)
Income (loss)(b)		21			(583	)

(a) The operating loss in 2003 included an impairment loss of $945 million ($573 million net of income taxes) related to Boston Generating’s long-lived assets.

(b) Net income for 2004 included an after-tax gain of $52 million related to the sale of Boston Generating in the second quarter of 2004.

Acquisition of AmerGen Energy Company, LLC

On December 22, 2003, Generation purchased British Energy plc’s (British Energy) 50% interest in AmerGen Energy Company, LLC (AmerGen). The resolution of purchase price contingencies related to the valuation of long-lived assets was finalized during the fourth quarter of 2004, reflecting the final purchase price of $267 million after working capital adjustments.

Prior to the purchase, Generation was a 50% owner of AmerGen and had accounted for the investment as an unconsolidated equity method investment. From January 1, 2003 through the date of closing, Generation recorded $47 million ($28 million, net of tax) of equity in earnings of unconsolidated affiliates related to its investment in AmerGen and recorded $382 million of purchased power from AmerGen. The book value of Generation’s investment in AmerGen prior to the purchase was $316 million.

In connection with the purchase of Unit No. 1 of the Three Mile Island (TMI) facility by AmerGen in 2000, AmerGen entered into an agreement with the seller whereby the seller would receive additional consideration based upon future purchase power prices through 2009. Under the terms of the agreement, approximately $11 million and $7 million had been accrued at December 31, 2005 and 2004, respectively. The amount accrued as of December 31, 2005 will be payable to the former owners of the TMI facility in the first quarter of 2006 and the amount accrued as of December 31, 2004 was paid in the first quarter of 2005. These payments represented contingent consideration for the original acquisition and have accordingly been reflected as an increase to the long-lived assets associated with the TMI facility, and are being depreciated over the remaining useful life of the facility.

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Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Selected Pro Forma and Consolidating Financial Information (Unaudited)

The following unaudited pro forma financial information gives effect to the acquisition on December 22, 2003 of the remaining 50% interest in AmerGen by Generation and the sale of Boston Generating by Generation on May 25, 2004, in each case, as if the transaction had occurred on January 1, 2003.

2004			Exelon As Reported		Sale of Boston Generating			Eliminating Entries			Pro Forma Exelon
Total operating revenues			$	14,133	$	248		$	—		$	13,885
Operating income (loss)				3,499		(49	)		—			3,548
Income from continuing operations				1,870		21			—			1,849
2003	Exelon As Reported		Acquisition of 50% of AmerGen		Sale of Boston Generating			Eliminating Entries(a)			Pro Forma Exelon
Total operating revenues	$	15,148	$	623	$	618		$	(382	)	$	14,771
Operating income (loss)		2,409		99		(954	)		—			3,462
Income (loss) from continuing operations		892		89		(583	)		(47	)		1,517

(a) Represents the elimination of intercompany revenues at AmerGen and equity in earnings from AmerGen in 2003.

The above unaudited pro-forma financial information should not be relied upon as being indicative of the historical results that would have been obtained if the transactions had actually occurred in prior periods nor of the results that might be obtained in the future.

Condensed Consolidating Balance Sheet at December 31, 2004 (Unaudited)

The following condensed consolidating financial information presents the financial position of Exelon and Sithe, as well as eliminating entries, related primarily to acquisition notes payable and receivables between Generation and Sithe.

December 31, 2004	Pro Forma Exelon		Sithe		Eliminating Entries			Exelon As Reported
Assets
Current assets	$	3,905	$	336	$	(361	)	$	3,880
Property, plant and equipment, net		21,212		270		—			21,482
Other noncurrent assets		16,643		750		(31	)		17,362
Total assets	$	41,760	$	1,356	$	(392	)	$	42,724
Liabilities and shareholders’ equity
Current liabilities	$	4,874	$	323	$	(361	)	$	4,836
Long-term debt		11,363		785		—			12,148
Other long-term liabilities(a)		15,947		181		36			16,164
Shareholders’ equity(b)		9,576		67		(67	)		9,576
Total liabilities and shareholders’ equity	$	41,760	$	1,356	$	(392	)	$	42,724

(a) Includes minority interest in consolidated subsidiaries.

(b) Includes preferred securities of subsidiaries.

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Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

4. Regulatory Issues

ComEd

Illinois Procurement Filing. In 2004, the ICC initiated and conducted a workshop process to consider issues related to retail electric service in the post-transition period (i.e., post 2006). Issues addressed included utility wholesale generation supply procurement methodology, rates, competition and utility service obligations and energy assistance programs. All interested parties were invited to participate. The end result was a report from the ICC to the Illinois General Assembly that was generally supportive of utilities competitively procuring generation supply through a reverse-auction process with full recovery of the supply costs from retail customers while being mindful of consumer protections. In the proposed reverse-auction model, qualified energy suppliers would compete in a transparent, fair and structured auction to provide energy to the utilities and their customers; winning bidders would provide the power needed at the price determined by the auction’s results; and the utilities would make no profit on the energy but would recover from customers the cost of procurement. The ICC staff would oversee the entire process.

On February 25, 2005, ComEd filed with the ICC seeking regulatory approval of tariffs that implement the methodologies supported by the report, including a proposal consistent with the reverse-auction process described above (the Procurement Case). As requested by ComEd, the ICC initiated hearings on the matter. The Illinois Attorney General, Citizens’ Utility Board (CUB), Cook County State’s Attorney’s Office and the Environmental Law and Public Policy Center subsequently filed a motion to dismiss the proceeding arguing that customers whose retail service has not been declared competitive are entitled to cost-based rates for power and its delivery and that the ICC lacked authority to approve rates based on the market value of power, as proposed by ComEd. On June 1, 2005 the administrative law judge denied the motion and, on July 13, 2005, the ICC denied the appeal. On December 5, 2005, the administrative law judge issued a proposed order that recommended that the ICC approve the competitive procurement process similar to the ComEd proposal. The administrative law judge reaffirmed an earlier ruling that the ICC has legal authority under the Public Utility Act to approve an auction process and the resulting rates. The proposed order also increased the regulatory oversight of the process.

On January 24, 2006, the ICC, by a unanimous vote, approved a reverse-auction competitive bidding process for procurement of power by ComEd for the time period after 2006. The procurement process is similar to the process described in the Procurement Case and the administrative law judge’s order described above, with some modifications to enhance consumer protection. The auction will be administered by an independent auction manager, with oversight by the ICC staff. The first auction is scheduled to take place during the fall of 2006, at which time ComEd’s entire load will be up for bid. To mitigate the effects of changes in future prices, the load will be staggered in three-year contracts. To further mitigate the impact on its residential customers of transitioning to this process, ComEd has offered to develop a “cap and deferral” proposal to ease the impact of the expected increase in rates on residential customers, some or all of which could require regulatory or legislative approval to implement. A cap and deferral proposal, generally speaking, would limit the procurement costs that ComEd could pass through to its customers for a specified period of time and allow ComEd to collect any unrecovered procurement costs in later years.

Several parties that were opposed to the Procurement Case have indicated that they will petition the ICC for rehearing and will challenge the ICC decision in court. ComEd also petitioned for rehearing of the ICC decision on certain issues, but that petition was denied by the ICC on February 8, 2006. It is

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Exelon Corporation and Subsidiary Companies

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(Dollars in millions, except per share data unless otherwise noted)

also possible that interested parties could introduce legislation in Illinois in an attempt to modify the procurement process or the rates that ComEd may charge consumers for the power ComEd purchases to meet the needs of consumers. The Illinois General Assembly has held hearings concerning generation procurement after 2006, and it may take action on this issue.

On September 1, 2005, the Illinois Attorney General, the Cook County State’s Attorney, CUB and the Environmental Law and Public Policy Center filed a two-count complaint in the Chancery Division of the Circuit Court of Cook County against the ICC and the individual ICC commissioners (the Procurement Litigation). The Procurement Litigation sought to block the ICC from approving the Procurement Case on the theory that the ICC lacked the authority to approve the rates because not all of the services that will be provided under the Procurement Case have been declared competitive and do not qualify for market-based rates. The legal argument underlying the Procurement Litigation is substantially similar to the legal argument that was presented to the administrative law judge, and to the ICC on appeal, and rejected by both, in the third quarter of 2005. ComEd intervened in the Procurement Litigation to deny the allegations in the complaint and sought a determination that the ICC has appropriate legal authority to approve the proposed electricity procurement process pending before the ICC in the Procurement Case. ComEd moved for summary judgment in the litigation, and the ICC moved to dismiss one claim in the litigation and for summary judgment on the other claim. A hearing on the motions was held on December 14, 2005 and the court issued a written order on January 20, 2006 denying the relief sought by the plaintiffs and dismissing the case with prejudice.

On October 17, 2005, ComEd and Generation filed an application with the FERC seeking approval that the proposed Illinois auction process meets FERC principles and that if Generation is selected as a winning bidder in the Illinois auction, the standard agreements under which Generation would sell energy, capacity and ancillary services to ComEd would be acceptable to the FERC. On December 16, 2005, the FERC issued an order granting both requests.

In November 2005, ComEd announced several actions intended to affirm the fact that ComEd is an independent entity, separate and distinct from its parent Exelon, and to strengthen ComEd’s ability to successfully manage some potentially challenging financial and strategic issues as Illinois continues its transition to restructuring after 2006. The actions include the election of a new board of directors of ComEd and selection of senior officers. The senior officers have responsibilities solely for ComEd.

The ICC, in its Order approving the Procurement Case, also ordered its Staff to “present orders initiating three separate rulemakings regarding demand response programs, energy efficiency programs and renewable energy resources to the Commission within thirty (30) days of the entry of this Order.” ComEd intends to participate in any such rulemakings.

Illinois Rate Case. On August 31, 2005, ComEd filed a rate case with the ICC, which seeks, among other things, to allocate the costs of delivering electricity and to adjust ComEd’s rates for delivering electricity effective January 2, 2007 (Rate Case). Several intervenors in the Rate Case, including the ICC staff and the Illinois Attorney General, have suggested, and provided testimony, that ComEd’s rates should actually be reduced. The commodity component of ComEd’s rates will be established by the reverse-auction process in accordance with the ICC order in the Procurement Case, assuming the ICC order on this matter is upheld upon appeal. The results of the Rate Case are not expected to be known until at least the third quarter of 2006.

Post 2006. ComEd cannot predict the results of the Rate Case before the ICC or whether the Illinois General Assembly might take action that could have a material impact on the outcome of the

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(Dollars in millions, except per share data unless otherwise noted)

regulatory process. However, if the price at which ComEd is allowed to sell energy beginning in 2007 is below ComEd’s cost to procure and deliver electricity, there may be material adverse consequences to Exelon. Exelon believes that these potential material adverse consequences could include, but may not be limited to, loss of ComEd’s investment grade credit rating and a possible reduction in other credit ratings, limited or lost access for ComEd to credit markets to finance operations and capital investment, and loss of ComEd’s capacity to enter into bilateral long-term energy procurement contracts, which would likely force ComEd to procure electricity at more volatile and potentially higher prices in the spot market. Moreover, to the extent ComEd is not permitted to recover its costs, ComEd’s ability to maintain and improve service may be diminished and its ability to maintain reliability may be impaired. In the nearer term, these prospects could have adverse effects on ComEd’s liquidity if vendors reduce credit or shorten payment terms or if ComEd’s financing alternatives become more limited and significantly less flexible. ComEd also cannot predict the long-term impact of customer choice for energy supply on its results of operations.

PJM Integration.On June 2, 2003, ComEd began receiving electric transmission reservation services from PJM Interconnection, LLC (PJM) and transferred control of ComEd’s Open Access Same Time Information System to PJM. On April 27, 2004, the FERC issued its order approving ComEd’s application to complete its integration into PJM, subject to certain stipulations. ComEd agreed to these stipulations and fully integrated its transmission facilities into PJM on May 1, 2004.

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 ComEd’s purchase power agreement (PPA) with Generation. The effect of the Agreement is to lower competitive transition charge (CTC) collections that ComEd receives from customers who take electricity from an alternative electric supplier or under the purchase power option (PPO) through 2006. The Agreement also allows customers to lock in current CTCs for multiple years. In 2005, 2004 and 2003, ComEd collected $105 million, $169 million and $304 million in CTC revenues, respectively.

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 Exelon’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 $10 million, $10 million and $23 million during 2005, 2004 and 2003, respectively.

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 certain customers with energy demands of at least three 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 will not have a right to take bundled service after June 2006 or to return to bundled rates if they choose an alternative supplier prior to June 2006.

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(Dollars in millions, except per share data unless otherwise noted)

On March 28, 2003, the ICC approved changes to ComEd’s real-time pricing tariff for non-residential customers, including those with energy demands of at least three MWs, who choose hourly energy supply for their electric power and energy. The ICC orders were affirmed on appeal.

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 reduction, 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 (20 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. Under Illinois statute, any impairment of goodwill would have no impact on the determination of the cap on ComEd’s allowed equity return during the transition period. As a result of the Illinois legislation, at December 31, 2005, ComEd had a regulatory asset related to recoverable transition costs with an unamortized balance of $43 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 in amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold. ComEd has not triggered the earnings sharing provision through 2005.

Open Access Transmission Tariff. On November 10, 2003, the FERC issued an order allowing ComEd to put into effect, 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 until January 2, 2007. During the third quarter of 2004, a settlement agreement was reached which was approved by the FERC during the fourth quarter of 2004, which established new rates that became effective May 1, 2004.

PECO

Partial Settlement before the PAPUC.On January 27, 2006, the PAPUC approved the Merger and a partial settlement regarding PECO’s distribution and transmission rates through 2010 and other financial commitments of PECO related to the Merger. The settlement reflected the conclusion of a process involving the majority of PECO customer groups during which PECO’s cost data, return on equity and estimated Merger synergies were reviewed. The provisions of the PAPUC order and partial settlement are contingent upon the completion of the Merger. The PAPUC order and partial settlement require PECO to implement rate reductions aggregating $120 million during a four-year period and to cap its rates through the end of 2010. During the rate cap period, the PAPUC retains the right to lower PECO’s rates if they are found to be excessive, and PECO retains the right to seek rate increases if certain events (such as 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) occur. The partial settlement also provides substantial funding for alternative energy and environmental projects, economic development, and expanded outreach and assistance for low-income customers. PECO also made commitments for enhanced customer service and reliability, commitments for charitable giving and employment, and a pledge to maintain its Philadelphia headquarters for a period of time. The total of these funding commitments is approximately $44 million, of which $30 million will be expensed at the time the Merger is completed. By separate motion, the PAPUC also indicated its intent to initiate a

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(Dollars in millions, except per share data unless otherwise noted)

separate investigation, to which PECO had agreed in the partial settlement, to examine issues related to a potential combination of Philadelphia Gas Works, which provides gas distribution service in the City of Philadelphia, into Exelon’s gas distribution businesses. This investigation will commence no earlier than 30 days after the close of the Merger. The outcome of this potential examination is uncertain. However, Exelon does not believe that the PAPUC has the authority to compel such a transaction if the two parties do not agree to terms through arms length negotiations.

Rate limitations.Pursuant to a settlement agreement related to the merger of Exelon, Unicom Corporation and PECO on October 20, 2000 (PECO / Unicom Merger) with the PAPUC, PECO was subject to agreed-upon electric service rate reductions of $200 million, in aggregate, for the period January 1, 2002 through December 31, 2005. As required by the 1998 electric restructuring settlement and as modified by the PECO / Unicom Merger-related settlement agreement, PECO is subject to rate 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.

ComEd and PECO

Through and Out Rates / SECA.In November 2004, the FERC issued two orders authorizing ComEd and PECO to recover amounts for a limited time during a specified transitional period as a result of the elimination of through and out (T&O) rates for transmission service scheduled out of, or across, their respective transmission systems and ending within pre-expansion PJM Interconnection, LLC (PJM) or Midwest Independent System Operators (MISO) territories. T&O rates were terminated pursuant to FERC orders, effective December 1, 2004. The new rates, known as Seams Elimination Charge/Cost Adjustment/Assignment (SECA), are collected from load-serving entities within PJM and MISO over a transitional period from December 1, 2004 through March 31, 2006, subject to refund, surcharge and hearing. As load-serving entities, ComEd and PECO are also required to pay SECA rates during the transitional period based on the benefits they receive from the elimination of T&O rates of other transmission owners within PJM and MISO.

During 2004, prior to the termination of T&O rates, ComEd and PECO had net T&O collections of approximately $50 million and $3 million, respectively. As a result of the November 2004 FERC orders and potential appeals, ComEd may see reduced net collections, and PECO may become a net payer of SECA charges. Since the inception of the SECA rates in December 2004, ComEd has recorded approximately $44 million of SECA collections net of SECA charges, including $40 million in 2005, while PECO has recorded $7 million of SECA charges net of SECA collections, including $6 million in 2005. Management of each of ComEd and PECO believes that appropriate reserves have been established in the event that such SECA collections are required to be refunded. However, as the above amounts collected under the SECA rates are subject to refund and surcharge and the ultimate outcome of the proceeding establishing SECA rates is uncertain, the result of this proceeding may have an effect on ComEd’s and PECO’s financial condition, results of operations and cash flows.

Customer Choice.All ComEd’s retail customers are eligible to choose an alternative electric supplier and most non-residential customers may also buy electricity from ComEd at market-basedprices under the PPO. One alternative supplier was approved to serve residential customers in the ComEd service territory. However, as of December 31, 2005, no residential customers have selected this alternative supplier. As of December 31, 2005, approximately 21,300 non-residential customers, or

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(Dollars in millions, except per share data unless otherwise noted)

33% of ComEd’s annual retail kilowatthour sales, had elected either the PPO or an alternative electric supplier. Customers who receive energy from an alternative supplier continue to pay a delivery charge.

All PECO customers may choose to purchase energy from an alternative electric supplier. As of December 31, 2005, approximately 44,500 customers, representing approximately 5% of PECO’s annual kilowatthour sales, had elected to purchase their electric energy from an alternative electric supplier. Customers who receive energy from an alternative electric supplier continue to pay delivery charges and CTCs.

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. Because ComEd did not take all of the output of these stations, actual collections were $68 million in 2005 and are expected to be a similar amount in 2006. Subsequent to 2006, there will be no further recoveries of decommissioning costs from ComEd’s customers. Any surplus funds after a nuclear station is decommissioned must be refunded to ComEd’s customers. The amounts collected by ComEd from retail customers are remitted to Generation. Effective January 1, 2004, the PAPUC approved an adjustment to PECO’s nuclear decommissioning cost adjustment clause permitting PECO to recover an additional $3.6 million annually, or $33 million compared to $29 million previously. The amounts collected by PECO from retail customers are remitted to Generation.

See Note 13—Nuclear Decommissioning and Spent Fuel Storage.

Generation

Market-Based Rates Filing.On July 5, 2005, the FERC approved Generation’s continued authority to charge market-based rates for wholesale sales of electricity, including to its affiliates ComEd and PECO. In the same order, the FERC stated that Generation had failed to address the affiliate abuse prong of the FERC’s market-based rate eligibility test and used that statement as the basis for instituting a proceeding under the provision of the Federal Power Act, section 206 and establishing a refund effective date of July 26, 2005 in the event that the FERC ultimately found that Generation did not, in fact, qualify for market-based rates. The FERC ordered Generation to make a compliance filing within 30 days of the order addressing the affiliate abuse and reciprocal dealing prong of the market-based rate test.

On August 4, 2005, Generation filed a Petition for Rehearing asking the FERC to rescind the part of its market-based rate order that had opened a section 206 investigation into the issue of affiliate abuse and established a refund effective date. Generation had addressed the affiliate abuse issue in its original November 2003 triennial update filing. The September 2004 filing had addressed only the new generation market power issue, as the FERC had directed. In the August 2005 filing, Generation noted the original reference in the September 2004 filing to the fact that FERC had previously found that circumstances existed that guarded against affiliate abuse. Generation further noted that as of both the September 2004 and August 2005 filings there had been no change in the circumstances cited in FERC’s original order granting authority to Generation to sell electricity at market-based rates. Generation’s pleading asks the FERC to either grant the rehearing request or consider the August 2005 filing to be the required compliance filing.

The July 2005 market-based rate order also directed Exelon to make compliance filings within 30 days of the order amending the market-based rate tariffs of Exelon’s various subsidiaries to include

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

prohibiting sales of electricity to Public Service and Gas Company (PSE&G), PSEG’s regulated utility, unless specific authority were sought for such sales under Section 203 of the Federal Power Act. These compliance filings were made in accordance with the order.

Exelon expects the FERC to make a decision in 2006. If the FERC were to suspend Generation’s market-based rate authority, Generation would be required to supply and implement a plan for mitigation of market power. FERC’s default mitigation would require Generation 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.

Service Life Extension.Upon the December 2003 acquisition of the remaining 50% interest in AmerGen, Generation changed its accounting estimates related to the depreciation of certain AmerGen generating facilities to conform with Generation’s depreciation policies. The estimated service lives were extended by 20 years for the three AmerGen stations. These changes were based on engineering and economic feasibility analyses performed by Generation. The service life extensions are subject to approval by the Nuclear Regulatory Commission (NRC) of renewals of the existing NRC operating licenses. In the first quarter of 2005, Generation applied the same depreciation estimated useful life assumption to its ownership share in the Salem Generating Station.

License Renewals. In December 2004, the NRC issued an order that will permit the Oyster Creek Generating Station (Oyster Creek) to operate beyond its license expiration in April 2009 if the NRC has not completed reviewing the application for renewal. In July 2005, Generation applied for license renewal for Oyster Creek, and is planning on filing for license renewals for TMI Unit 1 and the Clinton Nuclear Power Station (Clinton) on a timeline consistent and integrated with the other planned license renewal filings for the Generation nuclear fleet. On October 28, 2004, the NRC approved 20-year renewals of the operating licenses for Generation’s Dresden and Quad Cities generating stations. The licenses for Dresden Unit 2, Dresden Unit 3 and Quad Cities Units 1 and 2 were renewed to 2029, 2031 and 2032, respectively. On May 7, 2003, the operating licenses for Peach Bottom Unit 2 and Peach Bottom Unit 3 were renewed to 2033 and 2034, respectively. Depreciation provisions are based on the estimated useful lives of the stations, which assumes the renewal of the licenses for all nuclear generating stations. As a result, these license renewals had no impact on the Consolidated Statements of Income.

Exelon, ComEd, PECO and Generation

The Energy Policy Act of 2005.The Energy Policy Act of 2005 (the Energy Policy Act), which was signed into law on August 8, 2005, implements several significant changes intended to improve electric reliability, promote investment in electric facilities, streamline electric regulation, improve wholesale competition, address problems identified in the Western energy crisis and Enron collapse, promote fuel diversity and cleaner fuel sources, and promote greater efficiency in electric generation, delivery and use.

The Energy Policy Act also transfers to FERC certain additional authority. FERC obtains new authority to review the acquisition or merger of generating facilities, along with the responsibility to address more explicitly cross-subsidization issues in these situations. FERC now has the authority to approve siting of electric transmission facilities located in national interest electric transmission corridors if states cannot or will not act in a timely manner to approve siting. The Energy Policy Act also creates a self-regulating electric reliability organization with FERC oversight to enforce reliability rules.

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

In addition, the Energy Policy Act extends the Price-Anderson Act to December 31, 2025. See Note 20—Commitments and Contingencies for further discussion of the Price-Anderson Act.

Additionally, the Energy Policy Act repealed PUHCA effective February 8, 2006. Since Exelon was a registered holding company under PUHCA, Exelon and its subsidiaries were subject to a number of restrictions. These restrictions involved financings, investments and affiliate transactions. Exelon had an order under PUHCA authorizing financing transactions within certain limits. Exelon also had an order under PUHCA authorizing development activities, the formation of new intermediate subsidiaries for internal corporate structuring, internal corporate reorganizations, and investments in certain non-U.S. energy-related subsidiaries. PUHCA also limited the businesses in which Exelon could engage in and the investments that Exelon could make, and required that Exelon’s utility subsidiaries constituted a single system that could be operated in an efficient, coordinated manner. With the repeal of PUHCA, Exelon is no longer subject to those restrictions. However, Section 203 of the Federal Power Act, as amended by the Energy Policy Act and regulations thereunder, governs intercompany system financings and cash management arrangements, certain corporate internal reorganizations, and certain holding company acquisitions of public utility and holding company securities. FERC obtained additional jurisdiction for the review of affiliate transactions, and FERC’s financing jurisdiction resumes to the extent that it was preempted by PUHCA. With the repeal of PUHCA, the SEC’s financing jurisdiction under PUHCA for ComEd’s and PECO’s short-term financings and Generation’s financings reverted to FERC. Exelon’s financings are not subject to FERC jurisdiction.

On December 7, 2005, ComEd and PECO filed applications for short-term financing authority with the FERC in the amounts of $2.5 billion and $1.5 billion, respectively. In February 2006, ComEd and PECO received orders from the FERC approving their requests, effective February 8, 2006 through December 31, 2007.

Generation currently has blanket financing authority that it received from FERC in November 2000 that became effective again with the repeal of PUHCA. If the FERC proceeding relating to Generation’s market-based rate authority results in revocation of that authority, Generation’s blanket financing authority may also be revoked. If that financing authority is revoked, it is possible that the revocation of financing authority would be effective prospectively. It is also possible that the revocation of financing authority might be retroactive to October 2, 2005. FERC has adopted regulations that would grandfather prior SEC approvals of financings at a company’s election. The FERC regulations require that companies intending to issue securities in reliance on their SEC financing orders file with FERC a copy of their SEC financing order within 30 days after the effective date of PUHCA repeal. In light of the potential uncertainty relating to the possible revocation of FERC’s blanket financing authority, Exelon has filed its SEC financing order with the FERC. The SEC financing order contains certain terms, limits, and reporting requirements which Exelon continues to review to determine the extent to which it would be subject to such conditions.

To the extent that the SEC’s jurisdiction under PUHCA preempted certain aspects of state regulation of Exelon, the repeal of PUHCA will permit the states in which Exelon and its subsidiaries operate to adopt additional regulations if they so choose, absent any preemption by the FERC.

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

5. Accounts Receivable

Customer accounts receivable at December 31, 2005 and 2004 included estimated unbilled revenues associated with unread meters, representing an estimate for the unbilled amount of energy or services provided to customers, and allowance for uncollectible accounts as follows:

	2005		2004
Unbilled revenues	$	986	$	867
Allowance for uncollectible accounts		77		93

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 through November 2010 based on the November 2005 amendment to this agreement. At December 31, 2005, PECO had sold a $225 million interest in accounts receivable, consisting of a $195 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 $30 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable (see Note 11—Long-Term Debt). At December 31, 2004, PECO had sold a $225 million interest in accounts receivable, consisting of a $179 million interest in accounts receivable which PECO accounted for as a sale under SFAS No. 140 and a $46 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable and reflected on the consolidated balance sheets as long-term debt due within one year. 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, 2005 and 2004, PECO met this requirement and was not required to make any cash deposits.

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

6. Property, Plant and Equipment

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2005 and 2004:

	December 31,
Asset Category	2005		2004
Electric—transmission and distribution	$	14,156	$	13,479
Electric—generation		7,286		7,125
Gas—transmission and distribution		1,482		1,436
Common		476		501
Nuclear fuel		3,148		2,926
Construction work in progress		840		593
Asset retirement cost(a)		827		1,024
Other property, plant and equipment(b)		1,638		1,627
Total property, plant and equipment		29,853		28,711
Less accumulated depreciation(c)		7,872		7,229
Property, plant and equipment, net	$	21,981	$	21,482

(a) See Note 13—Asset Retirement Obligation and Spent Nuclear Fuel and Note 14—Conditional ARO for further information.

(b) Includes buildings under capital lease with a net carrying value of $40 million and $43 million at December 31, 2005 and 2004, respectively. The original cost basis of the buildings was $53 million and total accumulated amortization was $13 million and $10 million at December 31, 2005 and 2004, respectively.

(c) Includes accumulated amortization of nuclear fuel of $2,103 million and $1,976 million at December 31, 2005 and 2004, respectively.

As of December 31, 2005 and 2004, Exelon had recorded the following accumulated depreciation for regulated and unregulated property, plant and equipment:

	December 31, 2005				December 31, 2004
	Regulated		Unregulated		Regulated		Unregulated
Accumulated depreciation	$	3,425	$	4,447	$	3,173	$	4,056

Regulatory Accounting.ComEd’s and PECO’s depreciation expense, which is included in cost of service for rate purposes, includes the estimated cost of dismantling and removing plant from service upon retirement. For ComEd, removal costs reduce the related regulated liability. For PECO, removal costs are capitalized when incurred and depreciated over the life of the new asset constructed consistent with PECO’s regulatory recovery method. For more information, see Note 21—Supplemental Financial Information.

Service Life Extensions.Upon the December 2003 acquisition of the remaining 50% interest in AmerGen, Generation changed its accounting estimates related to the depreciation of certain AmerGen generating facilities to conform with Generation’s depreciation policies. See Note 4— Regulatory Issues for further information on service life extensions.

License Renewals. Depreciation provisions are based on the estimated useful lives of the stations, which assumes the renewal of the licenses for all nuclear generating stations. As a result, the receipt of license renewals has no impact on the Consolidated Statements of Income. See Note 4—Regulatory Issues for further information on license renewals.

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

7. Jointly Owned Electric Utility Plant

Exelon’s undivided ownership interests in jointly owned electric plant at December 31, 2005 and 2004 were as follows:

	Nuclear generation						Fossil fuel generation						Transmission/ Other
	Quad Cities		Peach Bottom		Salem(a)		Keystone		Conemaugh		Wyman
Operator		Generation		Generation		PSEG Nuclear		Reliant		Reliant		FP&L		(b),(c)
Ownership interest		75.00%		50.00%		42.59%		20.99%		20.72%		5.89%		(b),(c)
Exelon’s share at December 31, 2005:
Plant	$	363	$	449	$	181	$	171	$	217	$	2	$	62
Accumulated depreciation		67		241		42		107		138		1		28
Construction work in progress		51		22		78		5		1		—		—
Exelon’s share at December 31, 2004:
Plant	$	287	$	438	$	127	$	167	$	212	$	2	$	62
Accumulated depreciation		54		231		33		102		133		—		27
Construction work in progress		39		16		81		5		1		—		—

(a) Generation also owns a proportionate share in the fossil fuel combustion turbine, which is fully depreciated. The gross book value was $3 million at December 31, 2005 and 2004.

(b) PECO has a 22.00% ownership of 127 miles of 500,000 voltage lines located in Pennsylvania and a 42.55% ownership of 151 miles of 500,000 voltage lines located in Delaware and New Jersey.

(c) Generation has a 44.24% ownership interest in Merrill Creek Reservoir located in New Jersey with a book value of $1 million at December 31, 2005 and 2004.

Exelon’s undivided ownership interests are financed with its funds and all operations are accounted for as if such participating interests were wholly owned facilities. Exelon’s share of direct expenses of the jointly owned plants are included in the corresponding operating expenses on Exelon’s Consolidated Statements of Income.

8. Intangible Assets

Goodwill

Pursuant to SFAS No. 142, goodwill is not 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 requires unrecognized intangible assets to be valued and then 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.

Exelon has determined that the goodwill should have been assigned to a ComEd reporting unit as opposed to an Energy Delivery reporting unit as previously reported. As a result, Exelon assesses

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Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

goodwill impairment at its ComEd reporting unit; accordingly, any goodwill impairment charge at ComEd will affect Exelon’s results of operations as the goodwill impairment test for Exelon considers the cash flows of only ComEd.

The changes in the carrying amount of goodwill for the years ended December 31, 2005 and 2004 were as follows:

Balance as of January 1, 2004(a)	$	4,719
Resolution of certain tax matters(b)		(9	)
PECO / Unicom Merger severance adjustments		(5	)
Balance as of January 1, 2005(a)		4,705
Resolution of certain tax matters		(23	)
Impairment		(1,207	)
Balance as of December 31, 2005(a)	$	3,475

(a) Exelon’s goodwill balance at January 1, 2004, January 1, 2005 and December 31, 2005 is held at ComEd. See Note 22— Segment Information for further information regarding Exelon’s segments.

(b) Adjustment related to income tax refund claims and interest thereon. See Note 20—Commitments and Contingencies for further information.

2005 Annual Goodwill Impairment Assessment.The annual goodwill impairment assessment was performed as of November 1, 2005. The first step of the annual impairment analysis, comparing the fair value of ComEd, the reporting unit that holds all of Exelon’s goodwill, to its carrying value, including goodwill, indicated an impairment of goodwill existed. The second step of the analysis indicated ComEd’s goodwill was impaired by $1.2 billion. This impairment was primarily driven by the fair value of ComEd’s below market PPA with Generation, the end of ComEd’s regulatory transition period at December 31, 2006 and the elimination of related transition revenues, developments in the regulatory and political environment as of November 1, 2005, anticipated increases in capital expenditures in future years and decreases in market valuations of comparable companies that are used to estimate the fair value of ComEd. In its assessment to estimate the fair value of the ComEd reporting unit, Exelon used a probability-weighted, discounted cash flow model with multiple scenarios. The determination of the fair value was dependent on many sensitive, interrelated and uncertain variables including changing interest rates, utility sector market performance, capital structure, market prices for power, post 2006 rate regulatory structures, operating and capital expenditure requirements and other factors.

Changes from the assumptions used in the impairment review could possibly result in a future impairment loss of ComEd’s goodwill, which could be material. Illinois legislation provides that reductions to ComEd’s common equity resulting from goodwill impairments will have no impact on the determination of the rate cap on ComEd’s allowed equity return during the electricity industry restructuring transition period through 2006. See Note 4—Regulatory Issues for further discussion of ComEd’s earnings provisions.

2004 Annual Goodwill Impairment Assessment.The annual goodwill impairment assessment was performed as of November 1, 2004. The first step of the annual impairment analysis, comparing the fair value of a reporting unit to its carrying value, including goodwill, indicated no impairment of goodwill at ComEd. In its assessment to estimate the fair value of their reporting unit, Exelon used a probability-weighted, discounted cash flow models with multiple scenarios. The determination of the fair value was

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

dependent on many sensitive, interrelated and uncertain variables including changing interest rates, utility sector market performance, capital structure, market prices for power, post 2006 rate regulatory structures, operating and capital expenditure requirements and other factors.

Other Intangible Assets

Exelon’s other intangible assets, included in deferred debits and other assets, consisted of the following:

	December 31, 2005							December 31, 2004
	Gross		Accumulated Amortization			Net		Gross		Accumulated Amortization			Net
Amortized intangible assets:
Energy purchase agreement(a)	$	—	$	—		$	—	$	384	$	(27	)	$	357
Tolling agreement(a)		—		—			—		73		(5	)		68
Synthetic fuel investments(b)		264		(121	)		143		264		(56	)		208
Other		—		—			—		6		(6	)		—
Total amortized intangible assets		264		(121	)		143		727		(94	)		633
Other intangible assets:
Intangible pension asset		34		—			34		171		—			171
Total intangible assets	$	298	$	(121	)	$	177	$	898	$	(94	)	$	804

(a) These intangible assets were eliminated from Exelon’s Consolidated Balance Sheets upon the sale of Sithe on January 31, 2005. See Note 3—Acquisitions and Dispositions for further information regarding the sale of Sithe.

(b) See Note 12—Income Taxes for a description of Exelon’s right to acquire tax credits through investments in synthetic fuel-producing facilities.

In 2005, the intangible pension asset decreased by $137 million as a result of an annual actuarial valuation associated with Exelon’s pension plans. See Note 15—Retirement Benefits for additional information. For the year ended December 31, 2005, Exelon’s amortization expense related to intangible assets was $68 million, of which $4 million has been reflected as a reduction in revenues related to the energy purchase agreement and the tolling agreement. For the year ended December 31, 2004, Exelon’s amortization expense related to intangible assets was $90 million, of which $32 million has been reflected as a reduction in revenues related to the energy purchase agreement and the tolling agreement. Exelon’s amortization expense was not significant in 2003. Generation sold Sithe on January 31, 2005, which resulted in the elimination of the intangible assets related to Sithe’s energy purchase agreement and tolling agreement from Exelon’s Consolidated Balance Sheets. See Note 3—Acquisitions and Dispositions for further information regarding this sale. Exelon’s amortization expense associated with intangible assets related to its investments in synthetic fuel-producing facilities is expected to be in the range of $72 million to $77 million annually for 2006 and 2007.

9. 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 and compensation level. Exelon accounts for their ongoing severance plans in accordance with SFAS No. 112 and SFAS No. 88 and accrues amounts associated with severance benefits that are considered probable and that can be reasonably estimated.

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(Dollars in millions, except per share data unless otherwise noted)

The following tables present total salary continuance severance costs (benefits), recorded as an operating and maintenance expense, during 2005, 2004 and 2003:

Salary Continuance Severance	ComEd		PECO	Generation		Other (a)		Exelon
Expense (income) recorded—2005	(9	)(b)	1	(4	)(b) (c)	(2	)(b)	$	(14	)(b)(c)
Expense recorded—2004	10		3	2		17			32
Expense recorded—2003	61		16	38		20			135

(a) Other includes corporate operations, shared service entities, including Exelon Business Services Company (BSC), Enterprises and investments in synthetic fuel-producing facilities.

(b) Represents a reduction in previously recorded severance reserves.

(c) Excludes severance charges of $5 million related to Salem, of which Generation owns 42.59% and which is operated by PSEG Nuclear, LLC (PSEG Nuclear).

The following table provides a roll forward of the salary continuance severance obligations from January 1, 2004 through December 31, 2005:

Salary Continuance Obligations
Balance at January 1, 2004	$	139
Severance charges recorded		32
Cash payments		(87	)
Other adjustments		(15	)
Balance at January 1, 2005	$	69
Reduction in obligation estimate		(14	)(a)
Cash payments		(33	)
Balance at December 31, 2005	$	22

(a) Excludes severance charges of $5 million related to Salem, of which Generation owns 42.59% and which is operated by PSEG Nuclear.

10. Notes Payable and Short-Term Debt

	2005		2004		2003
Average borrowings	$	935	$	149	$	144
Maximum borrowings outstanding		2,416		622		1,288
Average interest rates, computed on a daily basis		3.49%		1.37%		1.25%
Average interest rates, at December 31		4.59%		2.43%		1.08%

On March 7, 2005, Exelon entered into a $2 billion term loan agreement. The loan proceeds were used to fund discretionary contributions of $2 billion to Exelon’s pension plans. On April 1, 2005, Exelon entered into a $500 million term loan agreement to reduce this $2 billion term loan. During the second quarter of 2005, $200 million of this $500 million term loan, as well as the remaining $1.5 billion balance on the $2 billion term loan described above, were repaid with the net proceeds received from the issuance of the $1.7 billion long-term senior notes presented in the table below. The $300 million outstanding balance under the $500 million term loan agreement bears interest at a variable rate determined, at Exelon’s option, by either the Base Rate or the Eurodollar Rate (as defined in the term loan agreement). On November 30, 2005, the term loan agreement was amended and restated to extend the agreement from December 1, 2005 to September 16, 2006.

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(Dollars in millions, except per share data unless otherwise noted)

At December 31, 2003, Exelon, along with ComEd, PECO and Generation, participated with a group of banks in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion unsecured revolving facility maturing on July 16, 2009, and the $750 million three-year facility was reduced to $500 million maturing on October 31, 2006. 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.

At December 31, 2005, Exelon, ComEd, PECO and Generation had the following sublimits and available capacity under the credit agreements and the indicated amounts of outstanding commercial paper:

Borrower	Bank Sublimit (a)		Available Capacity (b)		Outstanding Commercial Paper
Exelon	$	100	$	100	$	—
ComEd		650		623		459
PECO		350		350		220
Generation		400		353		311

(a) Sublimits under the credit agreements can change upon written notification to the bank group.

(b) Available capacity represents the bank sublimit net of outstanding letters of credit. The amount of commercial paper outstanding does not reduce the available capacity under the credit facilities.

Interest rates on advances under the credit facilities are based on either prime or the London Interbank Offering Rate (LIBOR) 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 LIBOR adder is 170 basis points.

The credit agreements require Exelon, ComEd, PECO and Generation to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and, in the case of Exelon and Generation, revenues from Sithe and interest on the debt of its project subsidiaries. The following table summarizes the minimum thresholds reflected in the credit agreements for the year ended December 31, 2005:

	Exelon	ComEd	PECO	Generation
Credit agreement threshold	2.65 to 1	2.25 to 1	2.25 to 1	3.25 to 1

At December 31, 2005, Exelon, ComEd, PECO and Generation were in compliance with the foregoing thresholds.

On February 10 through 13, 2006, Generation entered into separate additional credit facilities with aggregate bank commitments of $875 million. See Note 25—Subsequent Events for further information.

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(Dollars in millions, except per share data unless otherwise noted)

11. Long-Term Debt

	Rates	Maturity Date	December 31,
			2005			2004
Long-term debt
First Mortgage Bonds(a) (b):
Fixed rates	3.50%-8.375%	2006-2033	$	3,201		$	3,510
Floating rates	2.95%-3.40%	2012-2020		497			406
Notes payable and other(c)	4.45%-7.83%	2006-2035		3,928			2,411
Pollution control notes:
Floating rates	3.03%-3.55%	2016-2034		520			520
Notes payable—accounts receivable agreement	4.23%	2010		30			46
Sinking fund debentures	3.875%-4.75%	2008-2011		10			12
Sithe long-term debt(d)
Non-recourse project debt
Independence	8.50%-9.00%	2007-2013		—			499
Batavia	18.00%	2007		—			1
Subordinated debt	7.00%	2034		—			419
Total long-term debt(e)				8,186			7,824
Unamortized debt discount and premium, net				(19	)		(114	)
Fair-value hedge carrying value adjustment, net				(1	)		9
Long-term debt due within one year				(407	)		(427	)
Long-term debt			$	7,759		$	7,292
Long-term debt due to ComEd Transitional Funding Trust and PECO Energy Transition Trust( f) (g)
Payable to ComEd Transitional Funding Trust	5.44%-5.74%	2006-2008	$	988		$	1,341
Payable to PETT	6.05%-7.65%	2006-2010		2,975			3,456
Long-term debt due to ComEd Transitional Funding Trust and PECO Energy Transition Trust				3,963			4,797
Long-term debt due to ComEd Transitional Funding Trust and PECO Energy Transition Trust due within one year				(507	)		(486	)
Total long-term debt due to ComEd Transitional Funding Trust and PECO Energy Transition Trust			$	3,456		$	4,311
Long-term debt to other financing trusts ( f) (g)
Subordinated debentures to ComEd Financing II	8.50%	2027		155			155
Subordinated debentures to ComEd Financing III	6.35%	2033		206			206
Subordinated debentures to PECO Trust III	7.38%	2028		81			81
Subordinated debentures to PECO Trust IV	5.75%	2033		103			103
Total long-term debt to other financing trusts			$	545		$	545

(a) Utility plant of ComEd and PECO is subject to the liens of their respective mortgage indentures.

(b) Includes first mortgage bonds issued under the ComEd and PECO mortgage indentures securing pollution control bonds and notes.

(c) Includes capital lease obligations of $46 and $50 million at December 31, 2005 and 2004, respectively. Lease payments of $2 million, $2 million, $2 million, $2 million, $2 million and $36 million will be made in 2006, 2007, 2008, 2009, 2010 and thereafter, respectively.

(d) These amounts were removed from Exelon’s consolidated balance sheets following Generation’s sale of Sithe, which was completed on January 31, 2005. See Note 3—Acquisitions and Dispositions for further information. Prior to the sale, in addition to the stated interest rate, an additional 1.97% and 0.99% of interest on the carrying amount of the secured bonds payable was being credited due to debt premiums and 1.63% of interest on the carrying amount of the subordinated debt

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(Dollars in millions, except per share data unless otherwise noted)

discount was being incurred due to the debt discount recorded at the time of purchase. At December 31, 2004, there was $100 million of unamortized debt discount associated with Sithe long-term debt.

(e) Long-term debt maturities in the periods 2006 through 2010 and thereafter are as follows:

Year
2006	$	407
2007		231
2008		898
2009		28
2010		645
Thereafter		5,977
Total	$	8,186

(f) Effective July 1, 2003, PECO Trust IV, a financing subsidiary created in May 2003, was deconsolidated from the financial statements in conjunction with the adoption of FIN 46. Effective December 31, 2003, ComEd Financing II, ComEd Financing III, ComEd Transitional Funding Trust, PECO Trust III, and PETT were deconsolidated from the financial statements in conjunction with the adoption of FIN 46-R. Amounts owed to these financing trusts are recorded as debt to financing trusts within Exelon’s Consolidated Balance Sheets.

(g) Long-term debt to financing trusts maturities in the periods 2006 through 2010 and thereafter are as follows:

Year
2006	$	506
2007		986
2008		965
2009		700
2010		806
Thereafter		545
Total	$	4,508

Issuances of Long-Term Debt. The following long-term debt was issued during 2005:

Company	Type	Interest Rate	Maturity	Amount
Exelon	Senior notes	4.45%	June 15, 2010	$	400
Exelon	Senior notes	4.90%	June 15, 2015		800
Exelon	Senior notes	5.625%	June 15, 2035		500
ComEd	Pollution Control Revenue Bonds	Variable	March 1, 2017		91
Total issuances(a)				$	1,791

(a) Issuances exclude unamortized bond discounts of $3 million.

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(Dollars in millions, except per share data unless otherwise noted)

Debt Retirements and Redemptions.The following debt was retired, through tender, open market purchases, optional redemption or payment at maturity, during 2005:

Company	Type	Interest Rate	Maturity	Amount
Exelon	Notes payable for investments in synthetic fuel-producing facilities	6.00 to 8.00%	January 2008	$	62
ComEd	Pollution Control Revenue Bonds	6.75%	March 1, 2015		91
ComEd	First Mortgage Bonds	9.875%	June 15, 2020		54
ComEd	First Mortgage Bonds	7.00%	July 1, 2005		163
ComEd	Notes Payable	6.40%	October 15, 2005		107
Other					31
Total retirements				$	508

Debt totaling approximately $820 million was eliminated from Exelon’s Consolidated Balance Sheets as a result of the sale of Sithe on January 31, 2005. See Note 3—Acquisitions and Dispositions for further discussion regarding the sale of Sithe.

During 2005 and 2004, ComEd made scheduled payments of $354 million and $335 million, respectively, related to its obligation to the ComEd Transitional Funding Trust, and PECO made scheduled payments of $481 million and $393 million, respectively, related to its obligation to PETT.

Prepayment premiums of $2 million, unamortized discount of $2 million and debt issuance costs of $1 million associated with the early retirement of debt in 2005 have been deferred in Exelon’s regulatory assets and will be amortized to interest expense over the life of the related new debt issuance consistent with regulatory recovery.

See Note 16—Fair Value of Financial Assets and Liabilities for additional information regarding interest-rate swaps.

See Note 17—Preferred Securities for additional information regarding preferred stock.

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

12. Income Taxes

Exelon’s income tax expense (benefit) from continuing operations is comprised of the following components:

	For the Years Ended December 31,
	2005			2004			2003
Included in operations:
Federal
Current	$	376		$	406		$	282
Deferred		411			260			127
Investment tax credit amortization		(13	)		(13	)		(13	)
State
Current		86			86			78
Deferred		84			(26	)		(85	)
Total income tax expense	$	944		$	713		$	389
Included in cumulative effect of changes in accounting principles:
Deferred
Federal	$	(22	)	$	12		$	58
State		(5	)		5			11
Total income tax expense (benefit)		(27	)	$	17		$	69

Exelon’s effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:

	For the Years Ended December 31,
	2005		2004		2003
U.S. Federal statutory rate	35.0%		35.0%		35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	5.8		1.6		(0.5	)
Nondeductible goodwill impairment charge(c)	22.3		—		—
Synthetic fuel-producing facilities credit(a) (b)	(12.6	)	(8.4	)	(1.8	)
Qualified nuclear decommissioning trust fund income	0.8		(0.3	)	0.7
Manufacturer’s deduction	(0.8	)	—		—
Tax exempt income	(0.6	)	(0.4	)	(0.6	)
Nontaxable postretirement benefits	(0.6	)	(0.3	)	—
Amortization of investment tax credit	(0.5	)	(0.4	)	(0.8	)
Low income housing credit	—		(0.4	)	(1.1	)
Other	1.0		1.3		(0.7	)
Effective income tax rate	49.8%		27.7%		30.2%

(a) Change between 2005 and 2004 reflects ownership of all synthetic fuel-producing facilities for the full year in 2005 compared to five months in 2004.

(b) Change between 2004 and 2003 reflects investments in synthetic fuel-producing facilities made in the fourth quarter of 2003 and the third quarter of 2004. See Note 3—Acquisitions and Dispositions for additional information regarding investments in synthetic fuel-producing facilities.

(c) Change in effective income tax rate between 2005 and 2004 is primarily due to the goodwill impairment charge of $1.2 billion.

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

The tax effects of temporary differences giving rise to significant portions of Exelon’s deferred tax assets and liabilities as of December 31, 2005 and 2004 are presented below:

	2005			2004
Deferred tax liabilities:
Plant basis difference	$	(4,291	)	$	(4,178	)
Stranded cost recovery		(1,465	)		(1,632	)
Deferred debt refinancing costs		(49	)		(56	)
Total deferred tax liabilities		(5,805	)		(5,866	)
Deferred tax assets:
Deferred pension and postretirement obligations		396			985
Excess of tax value over book value of impaired assets(a)		41			44
Decommissioning and decontamination obligations		105			145
Unrealized loss on derivative financial instruments		195			57
Goodwill		6			6
Other, net		326			209
Total deferred tax assets		1,069			1,446
Deferred income tax liabilities (net) on the Consolidated Balance Sheets	$	(4,736	)	$	(4,420	)

(a) Includes write-downs of certain Enterprises investments.

In accordance with regulatory treatment of certain temporary differences, Exelon has recorded a net regulatory asset associated with deferred income taxes, pursuant to SFAS No. 71 and SFAS No. 109, of $789 million and $751 million at December 31, 2005 and 2004, respectively. See Note 21—Supplemental Financial Information for further discussion of Exelon’s regulatory asset associated with deferred income taxes.

ComEd and PECO have certain tax returns that are under review at the audit or appeals level of the IRS, and certain state authorities. Except for the tax positions discussed below, these reviews by governmental taxing authorities are not expected to have an adverse impact on the financial condition or result of operations of Exelon.

At December 31, 2005 and 2004, Exelon had recorded valuation allowances of $6 million and $9 million, with respect to deferred taxes associated with separate company state taxes. As of December 31, 2005, Exelon had net capital loss carryforwards for income tax purposes of approximately $129 million, which will expire after 2008.

Investments in Synthetic Fuel-Producing Facilities

Background.Exelon, through three separate wholly owned subsidiaries, owns interests in two limited liability companies and one limited partnership that own synthetic fuel-producing facilities. These facilities chemically convert coal, including waste and marginal coal, into a synthetic fuel which is used at power plants. Section 45k (formerly Section 29) of the Internal Revenue Code (IRC) provides tax credits for the sale of synthetic fuel produced from coal. These tax credits are scheduled to expire in December 2007. The expenses associated with the operations of these facilities exceed the related operating revenues and, therefore, these facilities generate operating losses. However, the tax credits provided by Section 45k of the IRC and the tax benefit related to the operating losses have

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(Dollars in millions, except per share data unless otherwise noted)

historically more than offset the operating losses. The value of the Section 45k tax credits is adjusted annually by an inflation factor published by the Internal Revenue Service (IRS) in April of the year following the year in which the credits are earned. Exelon’s right to acquire tax credits generated by the facilities was recorded as intangible assets which are amortized as the tax credits are earned.

Ownership Structure. The purchase price for Exelon’s investments in synthetic fuel-producing facilities is comprised of fixed and variable components. The fixed component is in the form of a non-recourse note that requires nonrefundable quarterly payments of principal and interest to the sellers. The variable component is based on the value of estimated tax credits that will be allocated to Exelon. Exelon’s subsidiaries are also required to make capital contributions based on the allocated amount of tax credits to the operators to fund the operating losses.

Phase-Out of Credits Based on Crude Oil Prices. Section 45k of the IRC contains a provision under which the tax credits are phased out (i.e., eliminated) in the event crude oil prices for a year exceed certain thresholds. Pursuant to Section 45k of the IRC, the value of the tax credit in a given year begins to be reduced if the annual average price per barrel of oil according to the First Purchaser index (Reference Price) within the year exceeds the threshold of the IRC-prescribed inflation-adjusted phase-out range. The tax credit is completely phased out if the Reference Price exceeds the maximum amount of the phase-out range. Given that the Reference Price is based on the current year’s annual average price, this amount must be estimated throughout the year based on actual prices to date. Recent events, such as terrorism, natural disasters and strong worldwide demand, have significantly increased the price of domestic crude oil and, therefore, have created uncertainty as to the value of future synthetic fuel tax credits.

The following table (in dollars) provides the actual and estimated phase-out prices per barrel of oil and the annual Reference Price for 2004 and 2005 in terms of the First Purchaser index:

	Actual 2004		Estimated 2005
Beginning of Phase-Out Range	$	51	$	52	(a)
End of Phase-Out Range		64		66	(a)
Annual Reference Price		37		51

(a) Estimated phase-out ranges are calculated using inflation rates published by the IRS after year end. The inflation rate used by Exelon to estimate the 2005 phase-out range was 2%.

As indicated in the table above, there was no phase-out of tax credits during 2004 since the annual oil Reference Price in terms of the First Purchaser index of $37 did not exceed the beginning phase-out price of $51. It is also not expected that there will be a phase-out for 2005 as the estimated reference price of $51 did not exceed the beginning of the estimated phase-out range of $52.

In order to assess the likelihood of a phase-out of tax credits and a potential impairment of the related intangible assets for 2005, Exelon must estimate the phase-out prices and the Reference Price based on actual prices to date. Actual prices to date are not readily available for the First Purchaser index which, as mentioned above, is prescribed by the IRS to calculate the Reference Price. In addition, the First Purchaser index does not include monthly quoted oil futures prices. As such, Exelon uses the New York Mercantile Exchange, Inc. index (NYMEX) to estimate an annual reference price. There are, however, certain pricing differences between the First Purchaser index and the NYMEX. The First Purchaser index includes prices for high sulfur, medium sulfur and low sulfur crude. The

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

NYMEX pricing is based on low sulfur crude only. Additionally, the First Purchaser index is based on wellhead pricing with no transportation cost component. The NYMEX pricing carries a delivery cost. There are also certain regional pricing differences between the First Purchaser index and NYMEX. Despite these pricing differences, Exelon believes the NYMEX provides a reasonable estimate of the annual Reference Price.

The following table (in dollars) provides the actual and estimated phase-out prices per barrel of oil and the annual reference price in NYMEX terms for 2005.

	Estimated 2005
Beginning of Phase-Out Range(a)	$	58
End of Phase-Out Range(a)		73
2005 Annual Average NYMEX		57

(a) Estimated phase-out ranges are calculated using inflation rates published by the IRS after year end. The inflation rate used by Exelon to estimate the 2005 phase-out range was 2%.

Based on the table above, the estimated annual phase-out threshold price based on the NYMEX would have to exceed $58 in 2005 for a phase-out to begin. Through December 31, 2005, the NYMEX closing price of a barrel of oil has averaged $57. Therefore, as of December 31, 2005, Exelon estimates that it will not exceed the threshold for a phase out of tax credits in 2005.

Impact on Financial Statements.Exelon’s interests in synthetic fuel-producing facilities, including mark-to-market gains, increased Exelon’s net income by $81 million and $70 million during 2005 and 2004, respectively. The increase in net income is reflected in the Consolidated Statements of Income as a benefit within income taxes, partially offset by charges to operating and maintenance expense, depreciation and amortization expense, interest expense and equity in losses of unconsolidated affiliates.

The net carrying value of the intangible assets was $143 million and $208 million at December 31, 2005 and 2004, respectively. See Note 8—Intangible Assets for additional information. The rising price of oil has resulted in the need to evaluate the intangible assets for impairment. An impairment of the intangible assets would occur if Exelon estimates that the synthetic fuel-producing facilities will not generate sufficient cash flows to cover the intangible assets balance as a result of tax credits being phased-out. A decision by the plant operators to cease operating the facilities could also result in the intangible assets being impaired. Based on the current available information, Exelon believes the operators will not cease to operate the facilities in 2006 and 2007. The intangible assets were not impaired as a result of the 2006 and 2007 average NYMEX future prices at December 31, 2005. If the intangible assets were to be impaired and the plants were to cease operations, Exelon would potentially be relieved of remaining payments on the non-recourse notes payable and would record a gain upon legal extinguishment of the notes payable for the remaining outstanding balance. However, this would occur in a period subsequent to the impairment being recorded.

The non-recourse notes payable principal balance was $158 million and $220 million at December 31, 2005 and 2004, respectively.

1999 Sale of Fossil Generating Assets

Exelon, through its ComEd subsidiary, has taken certain tax positions, which have been disclosed to the IRS, to defer the tax gain on the 1999 sale of its fossil generating assets. As of December 31, 2005 and 2004, deferred tax liabilities related to the fossil plant sale are reflected in Exelon’s

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Consolidated Balance Sheets with the majority allocated to ComEd and the remainder to Generation. Exelon’s ability to continue to defer all or a portion of this liability depends on whether its treatment of the sales proceeds as having been received in connection with an involuntary conversion is proper pursuant to applicable law. Exelon’s ability to continue to defer the remainder of this liability may depend in part on whether its tax characterization of a lease transaction ComEd entered into in connection with the sale is proper pursuant to applicable law. For instance, the IRS may argue that the lease transaction is of a type it has recently announced its intention to challenge, and Exelon understands that somewhat similar transactions entered into by other companies have been the subject of review and challenge by the IRS. A successful IRS challenge to ComEd’s positions would have the impact of accelerating future income tax payments and increasing interest expense related to the deferred tax gain that becomes currently payable. As of December 31, 2005, Exelon’s potential cash outflow, including tax and interest (after tax), could be as much as $951 million. If the deferral were successfully challenged by the IRS, it could negatively impact Exelon’s results of operations by as much as $135 million (after tax). Exelon’s management believes a reserve for interest has been appropriately recorded in accordance with FASB Statement No. 5, “Accounting for Contingencies” (SFAS No. 5); however, the ultimate outcome of such matters could result in unfavorable or favorable adjustments to the results of operations, and such adjustments could be material. Federal tax returns covering the period of the 1999 sale are currently under IRS audit. Final resolution of this matter is not anticipated for several years.

13. Nuclear Decommissioning and Spent Fuel Storage

Exelon has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. Exelon will pay for this obligation using trust funds that have been established for this purpose. These trust funds have been funded through prior and current collections from customers. The trust funds established for a particular plant may not be used to fund the decommissioning obligation of any other nuclear plant. Exelon believes that these funds, along with future collections from customers for decommissioning, will ultimately be sufficient to satisfy all required decommissioning-related activities.

The following table summarizes the most significant assets and liabilities associated with nuclear decommissioning included in Exelon’s Consolidated Balance Sheets as of December 31, 2005 and 2004:

December 31, 2005
Property, plant and equipment (asset retirement cost)	$	685
Nuclear decommissioning trust funds		5,585
Regulatory liability		(1,503	)
Asset retirement obligation		(3,921	)
Other comprehensive income, net		(76	)

December 31, 2004
Property, plant and equipment (asset retirement cost)	$	961
Nuclear decommissioning trust funds		5,262
Regulatory liability		(1,479	)
Asset retirement obligation		(3,981	)
Other comprehensive income, net		(62	)

214

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Nuclear Decommissioning Obligations

Generation assumed the responsibility for decommissioning the former ComEd and former PECO nuclear units as a result of a corporate restructuring effective January 1, 2001 in which Exelon separated its generation and other competitive businesses from its regulated energy delivery business at ComEd and PECO.

AmerGen, which became a wholly owned subsidiary of Generation in December 2003, assumed responsibility for decommissioning the Three Mile Island, Clinton and Oyster Creek units upon the original purchase of each unit in 1999, 1999 and 2000, respectively.

Generation will begin decommissioning activities for each plant once that plant ceases operations. The majority of Generation’s decommissioning activity is anticipated to begin after 2029. Generation currently makes decommissioning payments for its retired units; however, those amounts are not considered significant when compared to the total obligation.

As of December 31, 2005 and 2004, Exelon had recorded nuclear decommissioning obligations totaling $3,921 million and $3,981 million, respectively, which were determined in accordance with SFAS No. 143. See Note 1—Significant Accounting Policies for information regarding the adoption and application of SFAS No. 143.

Nuclear Decommissioning Trust Funds

The trust funds that have been established to satisfy Exelon’s nuclear decommissioning obligations were originally funded with amounts collected by customers. In certain circumstances, these trust funds will continue to be funded by future collections from customers.

The trusts associated with the former ComEd units and the former PECO units have been funded with amounts collected from the ComEd and PECO customers, respectively. Any funds remaining in these trusts after decommissioning has been completed are required to be refunded to ComEd or PECO’s customers as appropriate. Conversely, if there are insufficient funds in the trusts associated with the former ComEd units to pay for decommissioning costs, Generation is required to fund that shortfall. Any potential shortfall is determined on a plant-by-plant basis, since the trust funds established for any particular plant may not be used to fund the decommissioning obligations of any other plant.

If there are insufficient funds in the trusts associated with the former PECO units, PECO is allowed to collect additional amounts from the PECO customers, subject to certain limitations, as prescribed by an order from the PAPUC. Generally, PECO will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds compared to decommissioning obligations, as well as 5% of any additional shortfalls. This initial $50 million will be borne by Generation as required by the corporate restructuring in 2001. Accordingly, the order from the PAPUC currently allows PECO to seek additional collections to fund 95% of the shortfall, after the initial $50 million that is not eligible for reimbursement from the customers.

AmerGen is financially responsible for the decommissioning of the AmerGen plants and retains any funds remaining in the trusts after decommissioning of those plants has been completed. Any shortfall of funds necessary for decommissioning is required to be funded by AmerGen.

215

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

As of December 31, 2005 and 2004, nuclear decommissioning trust funds totaled $5,585 million and $5,262 million, respectively. See Note 16—Fair Value of Financial Assets and Liabilities for more information regarding the nuclear decommissioning trust funds as of December 31, 2005 and 2004.

Current Collections from Customers

Through 2006, ComEd is permitted to collect up to $73 million annually from customers to pay for decommissioning costs. These amounts are collected by ComEd and remitted to Generation on a monthly basis. In 2005 and 2004, ComEd collected and remitted to Generation a total of $68 million and $73 million, respectively. ComEd is not permitted to collect any amounts after 2006 to pay for decommissioning costs; accordingly, any trust fund deficiencies, as determined on a plant-by-plant basis, for decommissioning obligations related to the former ComEd plants will be funded by Generation.

PECO is permitted to collect amounts to fund decommissioning costs through the retirement dates of each of the former PECO nuclear units. Currently, PECO collects $33 million annually from customers to pay for these decommissioning costs. These amounts are collected by PECO and remitted to Generation on a monthly basis. Every five years, the PAPUC reviews the annual amount that PECO is allowed to collect from customers. In both 2005 and 2004, PECO collected and remitted to Generation $33 million. In the event the PAPUC reduces or eliminates the amount PECO is permitted to collect from customers, Generation anticipates that any trust fund deficiencies for decommissioning obligations related to the former PECO plants would be funded by Generation.

AmerGen does not currently collect any amounts from customers, nor is there any mechanism by which Generation can seek to collect additional amounts from customers in order to pay the decommissioning costs of the AmerGen units.

Accounting Implications of the Agreements with ComEd and PECO

Impact on the Statements of Income

As discussed above, the ComEd and PECO customers are entitled to a refund of any excess, as determined on a plant-by-plant basis, of trust funds that remain after the completion of decommissioning activities. Because the funds held in trust currently exceed the total estimated decommissioning obligation, Exelon does not recognize in the statement of income the net impacts of decommissioning the former ComEd and former PECO units. However, should the decommissioning obligations associated with the former ComEd units exceed the related decommissioning assets, Exelon will no longer maintain a regulatory liability to ComEd customers, but rather reflect the net impacts of decommissioning activities related to these plants in the statements of income.

Decommissioning impacts, including the accretion of the decommissioning obligation (which is included in operating and maintenance expense in the statements of income) and the income of the trust funds (net of applicable taxes) associated with the former ComEd and former PECO units, are offset within the statements of income with an equal adjustment to the regulatory liability. The decommissioning of the AmerGen units are reflected in the statements of income, as there are no regulatory agreements associated with these units.

Impact on the Statements of Other Comprehensive Income

Exelon does not reflect any net activity within the statement of other comprehensive income related to the unrealized gains and losses for the trust funds established to fund the decommissioning

216

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

liabilities of the former PECO units as these unrealized gains and losses are not anticipated to ultimately be included in the statement of income as a result of the current accounting discussed above. Unrealized gains and losses (after applicable taxes) related to the former ComEd units are also offset within the statement of other comprehensive income. The gross unrealized gains and losses in the trust funds of the former ComEd and PECO units are tax-effected at the applicable tax rates, so that the associated deferred tax assets and liabilities can be appropriately calculated and recorded.

The net unrealized gains and losses associated with AmerGen are included in the statement of other comprehensive income, since the accounting treatment described above does not apply to AmerGen.

Impact on the Balance Sheet

The decommissioning liabilities associated with the former ComEd, former PECO and AmerGen units are reflected as an asset retirement obligation (ARO) in the long-term liability section of the balance sheet. AROs represent legal obligations associated with the retirement of tangible long-lived assets. Changes in the ARO resulting from revisions to the timing or amount of future undiscounted cash flows are generally recognized through a corresponding increase or decrease to the carrying value of that plant. This adjustment is reflected in property, plant and equipment as an asset retirement cost (ARC), and is amortized on a straight-line basis over the life of that plant. The adjustments that are required to eliminate the decommissioning impacts on the statement of income and statement of other comprehensive income associated with the former ComEd and PECO plants are recorded through changes in regulatory liabilities.

The following table provides a roll forward of the ARO on Exelon’s Consolidated Balance Sheets, from January 1, 2004 to December 31, 2005:

Asset retirement obligation at January 1, 2004(a)	$	2,997
Net increase resulting from updates to estimated future cash flows		780
Accretion expense		210
Additional liabilities incurred(b)		6
Payments to decommission retired plants		(12	)
Asset retirement obligation at December 31, 2004(a)		3,981
Net decrease resulting from updates to estimated future cash flows		(281	)
Accretion expense		243
Liability reclassified and disposed(c)		(8	)
Payments to decommission retired plants		(14	)
Asset retirement obligation at December 31, 2005	$	3,921

(a) Includes amounts not related to nuclear decommissioning.

(b) Additional liabilities incurred are primarily due to the consolidation of Sithe.

(c) Represents the reclassification of $(5) million primarily related to fossil and hydroelectric generating facilities and $(3) million related to liabilities disposed as a result of the sale of Sithe on January 31, 2005.

2005 and 2004 ARO Updates

In 2005, Exelon recorded a $281 million net decrease in the ARO resulting from revisions to estimated future nuclear decommissioning cash flows. This decrease resulted primarily from a year-

217

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

over-year decline in the cost escalation factors used to estimate future undiscounted costs, partially offset by an increase resulting from updated decommissioning cost studies received for two nuclear stations. Both the updated cost escalation factors and the updated cost studies were provided by independent third-party appraisers.

In 2004, Exelon recorded a $780 million net increase in the ARO resulting from revisions to estimated future nuclear decommissioning cash flows. This increase resulted primarily from updated decommissioning cost studies and changes in cost escalation factors used to estimate future undiscounted costs, both of which were provided by independent third-party appraisers.

Spent Nuclear Fuel

Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy (DOE) is responsible for the development of a repository for the disposal of spent nuclear fuel (SNF) and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from its nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation pays the DOE one mill ($.001) per kilowatt-hour of net nuclear generation for the cost of nuclear fuel long-term disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts 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 2012. This extended delay in SNF acceptance by the DOE has led to Generation’s adoption of dry cask storage at its Dresden, Quad Cities, Oyster Creek and Peach Bottom stations and its consideration of dry cask storage at other stations.

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. PECO’s fee has been paid. Pursuant to the Standard Contracts, 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, 2005, the unfunded liability for the one-time fee with interest was $906 million. Interest accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect, for calculation of the interest accrual at December 31, 2005, was 3.983%. The liabilities for spent nuclear fuel disposal costs, including the one-time fee, were transferred to Generation as part of the 2001 corporate restructuring. The one-time fee obligation for the AmerGen units, except for Clinton, remains with the prior owner. Clinton has no outstanding obligation.

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 granted the Government’s motion to dismiss claims other than the breach of contract claims. Also on June 10, 2003, the Court denied the Government’s summary judgment motions and set the case for trial on damages for November 2004.

In July 2000, PECO entered into an agreement (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

218

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

1998 as required by the Standard Contracts. Under the Amendment, the DOE agreed to provide PECO with credits against PECO’s future contributions to the Nuclear Waste Fund 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 grounds 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 provided 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 Contracts would remain in effect and the parties would return to pre-Amendment status. 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, which Generation paid in 2004. The letter also demanded $1.5 million of interest that was accrued as of that date and Generation continued to record an interest expense each subsequent month. Generation 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.

On July 21, 2004, Exelon and the U.S. Department of Justice, in close consultation with the DOE, reached a settlement under which the government will reimburse Generation for costs associated with storage of spent fuel at Generation’s nuclear stations pending DOE’s fulfillment of its obligations. Under the agreement, Generation immediately received $80 million in gross reimbursements for storage costs already incurred ($53 million net after considering amounts due from Generation to co-owners of certain nuclear stations), with additional amounts to be reimbursed annually for future costs. Also under the agreement, during the third quarter of 2004, Generation made full reimbursement of $41.9 million to the Nuclear Waste Fund for prior credits plus lost earnings as set forth in the DOE Contracting Officer’s letter dated August 14, 2003. In 2005, Generation received $58 million in gross reimbursements for storage costs incurred between October 1, 2003 and June 30, 2005, ($35 million net, after considering amounts due from Generation to co-owners and previous owners of certain nuclear stations). As of December 31, 2005, the amount of spent fuel storage costs for which reimbursement will be requested from the DOE under the settlement agreement is $14 million gross, which is recorded within accounts receivable, other. This amount is comprised of $6 million, which has been recorded as a reduction to operating and maintenance expense, and $5 million, which has been recorded as a reduction to capital expenditures. The remaining $3 million represents amounts owed to

219

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

the co-owners of the Peach Bottom and Quad Cities generating facilities. In all cases, reimbursements will be made only after costs are incurred and only for costs resulting from DOE delays in accepting the fuel.

14. Conditional ARO

As of December 31, 2005, Exelon adopted FIN 47, which clarified that a legal obligation associated with the retirement of a long-lived asset whose timing and/or method of settlement are conditional on a future event is within the scope of SFAS No. 143. Under FIN 47, Exelon is required to record liabilities associated with its conditional AROs at their estimated fair values if those fair values can be reasonably estimated.

Determination of Conditional AROs

The adoption of FIN 47 required Exelon to update an existing inventory, originally created for the adoption of SFAS No. 143, and to determine which, if any, of the conditional AROs could be reasonably estimated. The significant conditional AROs identified by ComEd and PECO included abatement and disposal of equipment and buildings contaminated with asbestos and Polychlorinated Biphenyls (PCBs). The significant conditional AROs identified by Generation included plant closure costs associated with its fossil and hydroelectric generating stations, including asbestos abatement, removal of certain storage tanks and other decommissioning-related activities.

The ability to reasonably estimate a conditional ARO was a matter of management judgment, based upon management’s ability to estimate a settlement date or range of settlement dates, a method or potential method of settlement and probabilities associated with the potential dates and methods of settlement of its conditional AROs. In determining whether their conditional AROs could be reasonably estimated, management considered Exelon’s past practices, industry practices, management’s intent and the estimated economic lives of the assets. The management of Exelon concluded that all significant conditional AROs could be reasonably estimated.

Exelon was required to measure the conditional AROs at fair value using the methodology prescribed by FIN 47. The transition provisions of FIN 47 required Exelon to apply this measurement back to the historical periods in which the conditional AROs were incurred, resulting in a remeasurement of these obligations at the latter of the date that the related assets were placed into service or acquired or the date that the applicable law or environmental regulation became effective. The fair values of the conditional AROs were then estimated using a probability-weighted, discounted cash flow model with multiple scenarios, if applicable. The present value of future estimated cash flows was calculated using credit-adjusted, risk-free rates in order to determine the fair value of the conditional AROs at the time of adoption of FIN 47.

Conditional AROs of $231 million were recorded as of December 31, 2005. Changes in management’s assumptions regarding settlement dates, settlement methods or assigned probabilities could have had a material effect on the liabilities recorded at December 31, 2005 as well as the associated cumulative effect of a change in accounting principle and associated regulatory assets recorded.

Effect of Adopting FIN 47

FIN 47 required that Exelon recognize the following amounts within its financial statements upon the adoption of FIN 47: (i) a liability for any existing conditional AROs adjusted for cumulative accretion

220

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

to December 31, 2005; (ii) an ARC capitalized as an increase to the carrying amount of the associated long-lived assets; and (iii) cumulative depreciation on the ARC. The transition guidance in FIN 47 required that its adoption be effected through a cumulative change in accounting principle measured as the difference between the amounts recognized in the financial statements prior to the adoption of FIN 47 for conditional AROs and the amounts recognized as of December 31, 2005 pursuant to FIN 47. Exelon had previously recognized $39 million as removal costs within regulatory liabilities associated with conditional AROs that were reclassified to a conditional ARO liability upon the adoption of FIN 47.

After considering the transitional guidance included in FIN 47, Exelon recorded a charge of $42 million (net of income taxes of $27 million) as a cumulative effect of a change in accounting principle in connection with its adoption. In addition, due to the application of SFAS No. 71, which is further described in Note 1—Significant Accounting Policies, Exelon recorded regulatory assets of $104 million associated with the adoption of FIN 47.

The following table presents the line items within Exelon’s Consolidated Statements of Income for the year ended December 31, 2005 and the Consolidated Balance Sheets at December 31, 2005 that were affected by the adoption of FIN 47:

Consolidated statements of income line item:
Cumulative effect of a change in accounting principle (net of income taxes of $(27))(a)	$	(42	)
Consolidated balance sheets line items—increase (decrease):
Property, plant and equipment, net(b)		19
Regulatory assets(c)		13
Deferred income taxes (noncurrent liability)		(27	)
Asset retirement obligations(d)		231
Regulatory liabilities(e)		(130	)

(a) Represents the difference between the conditional ARO, net ARC and regulatory assets and liabilities recorded upon adoption, net of income taxes.

(b) Represents capitalized ARC of $52 million as an increase to the carrying amount of the associated long-lived assets, net of accumulated depreciation of $33 million on the ARC.

(c) Represents an increase to regulatory assets at PECO pursuant to SFAS No. 71 for amounts expected to be recovered from customers.

(d) Represents a liability for existing conditional AROs adjusted for cumulative accretion to December 31, 2005.

(e) Represents an increase to regulatory assets (which are netted with regulatory liabilities) at ComEd of $91 million pursuant to SFAS No. 71 for amounts expected to be recovered from customers and removal costs within regulatory liabilities of $39 million at ComEd that were reclassified to the asset retirement obligations liability.

See Note 1—Significant Accounting Policies for net income and earnings per common share for 2005, 2004 and 2003, adjusted as if FIN 47 had been applied effective during the entirety of those years. The following table presents, on a pro forma basis, what the liability for conditional AROs would have been had FIN 47 been applied during the years 2004 and 2003. These pro forma amounts are estimated based upon the information, assumptions, and interest rates used to measure the liability for conditional AROs recognized upon adoption of FIN 47 as of December 31, 2005.

Pro forma liability for conditional AROs, January 1, 2003(a)	$	196
Pro forma liability for conditional AROs, December 31, 2003(a)		208
Pro forma liability for conditional AROs, December 31, 2004(a)		221

(a) Includes AROs related to fossil and hydroelectric generating stations at Generation previously recorded upon the adoption of SFAS No. 143.

221

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Prospective Accounting Methodology Under FIN 47

The liabilities associated with conditional AROs will be adjusted on an ongoing basis due to the passage of time, new laws and regulations and revisions to either the timing or amount of the original estimates of undiscounted cash flows. These adjustments could have a significant impact on Exelon’s Consolidated Statements of Income and Consolidated Balance Sheets, assuming the provisions of SFAS No. 71 continue to apply.

The liabilities recorded as of December 31, 2005 related to the conditional AROs of Exelon will be accreted to their full estimated settlement amounts through the estimated ultimate settlement dates. For Generation, this accretion charge will be recorded as an operating and maintenance expense within the Consolidated Statements of Income. For ComEd and PECO, most of this accretion charge will be recorded as an increase to their regulatory assets due to the application of SFAS No. 71.

The net ARC recorded as of December 31, 2005 by Exelon will be depreciated over the remaining lives of the related long-lived assets. For Generation, this charge will be recorded as depreciation and amortization expense within the Consolidated Statements of Income. For ComEd and PECO, most of this depreciation charge will be recorded as an increase to their regulatory assets due to the application of SFAS No. 71.

15. Retirement Benefits

Exelon sponsors defined benefit pension plans and postretirement welfare benefit plans for essentially all ComEd, PECO, Generation (except for AmerGen) and BSC employees and certain employees of Enterprises. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in Exelon-sponsored cash balance pension plans. Substantially all non-union employees hired prior to January 1, 2001 were offered a choice to remain in Exelon’s traditional pension plan or transfer to a cash balance pension plan for management employees. Employees of AmerGen participate in separate defined benefit pension plans and postretirement welfare benefit plans sponsored by AmerGen. In 2005, AmerGen offered its employees a choice to remain in their traditional benefit formula or convert to a cash balance formula. Exelon has not yet received a ruling with respect to its non-union plan due to the IRS temporary moratorium on issuing any ruling to plans that were involved in a “conversion” from a traditional to a cash balance formula.

222

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Exelon made discretionary aggregate contributions of approximately $2 billion to its traditional and cash balance pension plans in 2005. These contributions were initially funded through borrowings under a short-term loan agreement, which were subsequently refinanced with long-term senior notes, as further described in Note 11—Long-Term Debt.

The funded status of the pension obligation refers to the difference between plan assets and estimated obligations of the plan. The funded status may change over time due to several factors, including contribution levels, assumed discount rates and assumed long-term rates of return on plan assets. Changes in these factors could impact the funded status of the pension obligation.

The following tables provide a roll forward of the changes in the benefit obligations and plan assets for the most recent two years:

	Pension Benefits						Other Postretirement Benefits
	2005			2004			2005			2004
Change in benefit obligation:
Net benefit obligation at beginning of year	$	9,775		$	8,758		$	2,988		$	3,019
Service cost		144			128			89			78
Interest cost		546			545			175			163
Plan participants’ contributions		—			—			22			17
Plan amendments		5			—			(17	)		(106	)
Actuarial loss (gain)		351			964			239			(10	)
Curtailments/settlements		—			(19	)		—			—
Special accounting costs		—			—			—			16
Gross benefits paid		(574	)		(601	)		(199	)		(189	)
Net benefit obligation at end of year	$	10,247		$	9,775		$	3,297		$	2,988
Change in plan assets:
Fair value of plan assets at beginning of year	$	7,014		$	6,442		$	1,246		$	1,171
Actual return on plan assets		612			723			58			115
Employer contributions		2,008			450			214			132
Plan participants’ contributions		—			—			22			17
Gross benefits paid		(574	)		(601	)		(199	)		(189	)
Fair value of plan assets at end of year	$	9,060		$	7,014		$	1,341		$	1,246

The following table provides a reconciliation of benefit obligations, plan assets and funded status of the plans:

	Pension Benefits						Other Postretirement Benefits
	2005			2004			2005			2004
Fair value of plan assets at end of year	$	9,060		$	7,014		$	1,341		$	1,246
Net benefit obligations at end of year		10,247			9,775			3,297			2,988
Funded status (plan assets less plan obligations)		(1,187	)		(2,761	)		(1,956	)		(1,742	)
Amounts not recognized
Unrecognized net actuarial loss		3,339			2,954			1,245			1,046
Unrecognized prior service cost (benefit)		159			170			(370	)		(445	)
Unrecognized net transition obligation (asset)		—			(4	)		67			76
Net amount recognized	$	2,311		$	359		$	(1,014	)	$	(1,065	)

223

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

The following table provides a reconciliation of the amounts recognized in the Consolidated Balance Sheets as of December 31, 2005 and 2004:

	Pension Benefits						Other Postretirement Benefits
	2005			2004			2005			2004
Prepaid benefit cost	$	2,358		$	407		$	—		$	—
Accrued benefit cost		(47	)		(48	)		(1,014	)		(1,065	)
Additional minimum liability		(2,202	)		(2,352	)		—			—
Intangible asset		34			171			—			—
Accumulated other comprehensive income		2,168			2,181			—			—
Net amount recognized	$	2,311		$	359		$	(1,014	)	$	(1,065	)

The accumulated benefit obligation (ABO) for all defined benefit pension plans was $9,234 million and $9,006 million at December 31, 2005 and 2004, respectively. On an ABO basis, the plans were funded at 98% at December 31, 2005 compared to 78% at December 31, 2004. On a projected benefit obligation basis, the plans were funded at 88% at December 31, 2005 compared to 72% at December 31, 2004.

The following table provides the projected benefit obligation, ABO, and fair value of plan assets for pension plans with an ABO in excess of plan assets. The table below is also representative of all pension plans with a projected benefit obligation in excess of plan assets.

	December 31,
	2005		2004
Projected benefit obligation	$	9,457	$	9,775
Accumulated benefit obligation		8,463		9,006
Fair value of plan assets		8,196		7,014

The following table provides the components of the net periodic benefit costs for the years ended December 31, 2005, 2004 and 2003. The table reflects an annualized reduction in 2005 and 2004 net periodic postretirement benefit cost of $40 million and $33 million, respectively, related to a Federal subsidy provided under the Prescription Drug Act. This subsidy has been accounted for under FSP FAS 106-2, as described in Note 1—Significant Accounting Policies. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.

	Pension Benefits									Other Postretirement Benefits
	2005			2004			2003			2005			2004			2003
Service cost	$	144		$	128		$	109		$	89		$	78		$	68
Interest cost		546			545			519			175			163			167
Expected return on assets(a)		(767	)		(611	)		(584	)		(98	)		(90	)		(75	)
Amortization of:
Transition obligation (asset)		(4	)		(4	)		(4	)		9			10			10
Prior service cost		16			15			16			(91	)		(81	)		(54	)
Actuarial loss		121			73			23			81			44			47
Curtailment/settlement charges		—			22			59			—			2			21
Net periodic benefit cost	$	56		$	168		$	138		$	165		$	126		$	184
Special termination benefits charge	$	—		$	—		$	—		$	—		$	16		$	48
Other additional information:
Increase (decrease) in other comprehensive income (net of tax)	$	10		$	(392	)	$	26		$	—		$	—		$	—

224

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

(a) The increase in expected return on pension assets during 2005 compared to 2004 and 2003 was primarily attributable to discretionary pension contributions of $2 billion made during the first quarter of 2005.

Exelon’s costs of providing pension and postretirement benefit plans are dependent upon a number of factors, such as the rates of return on pension plan assets, discount rate, and the rate of increase in health care costs. In 2003, the additional minimum liability was reduced by $69 million and shareholders’ equity increased by $26 million (net of income taxes) as a result of an annual actuarial valuation associated with Exelon’s pension plans. In 2004, the additional minimum pension liability was increased by $606 million and shareholders’ equity decreased by $392 million (net of income taxes) as a result of an annual actuarial valuation associated with Exelon’s pension plans. In 2005, the additional minimum pension liability was reduced by $150 million and shareholders’ equity primarily increased by $10 million (net of income taxes) as a result of an annual actuarial valuation associated with Exelon’s pension plans.

Special accounting costs of $0, $16 million and $48 million in 2005, 2004 and 2003, respectively, represent special health and welfare severance benefits offered to terminated employees. These costs were recorded pursuant to SFAS No. 112. Prior service cost is amortized on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans.

The following weighted average assumptions were used to determine the benefit obligations at December 31, 2005, 2004 and 2003:

	Pension Benefits			Other Postretirement Benefits
	2005 (a)	2004	2003	2005(a)	2004	2003
Discount rate	5.60%	5.75%	6.25%	5.60%	5.75%	6.25%
Rate of compensation increase	4.00%	4.00%	4.00%	4.00%	4.00%	4.00%
Health care cost trend on covered charges	N/A	N/A	N/A	8.00% decreasing to ultimate trend of 5.0% in 2010	9.00% decreasing to ultimate trend of 5.0% in 2010	10.00% decreasing to ultimate trend of 4.5% in 2011

(a) Assumptions used to determine year-end 2005 benefit obligations will be the assumptions used to estimate the expected costs of benefits in 2006.

The following weighted average assumptions were used to determine the net periodic benefit costs for years ended December 31 2005, 2004 and 2003:

	Pension Benefits			Other Postretirement Benefits
	2005	2004	2003	2005	2004	2003
Discount rate	5.75%	6.25%	6.60-6.75%	5.75%	6.25%	6.60-6.75%
Expected return on plan assets	9.00%	9.00%	9.00%	8.30%	8.33-8.35%	8.40%
Rate of compensation increase	4.00%	4.00%	4.00%	4.00%	4.00%	4.00%
Health care cost trend on covered charges	N/A	N/A	N/A	9.00% decreasing to ultimate trend of 5.0% in 2010	10.00% decreasing to ultimate trend of 4.5% in 2011	8.50% decreasing to ultimate trend of 4.5% in 2008

225

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

In managing its pension and postretirement plan assets, Exelon utilizes a diversified, strategic asset allocation to efficiently and prudently generate investment returns that will meet the objectives of the investment trusts that hold the plan assets. Asset / Liability studies that incorporate specific plan objectives as well as assumptions regarding long-term capital market returns and volatilities generate the specific asset allocations for the trusts. In general, Exelon’s investment strategy reflects the belief that over the long term, equities are expected to outperform fixed-income investments. The long-term nature of the trusts make them well suited to bear the risk of added volatility associated with equity securities, and, accordingly, the asset allocations of the trusts usually reflect a higher allocation to equities as compared to fixed-income securities. Non-U.S. equity securities are used to diversify some of the volatility of the U.S. equity market while providing comparable long-term returns. Alternative asset classes, such as private equity and real estate, may be utilized for additional diversification and return potential when appropriate. Exelon’s investment guidelines limit exposure to investments in more volatile sectors.

Exelon generally maintains approximately 60% of its plan assets in equity securities and 40% of its plan assets in fixed-income securities. On a quarterly basis, Exelon reviews the actual asset allocations and follows a rebalancing procedure in order to remain within an allowable range of these targeted percentages.

In selecting the expected rate of return on plan assets, Exelon considers historical returns for the types of investments that its plans hold. Historical returns and volatilities are modeled to determine asset allocations that best meet the objectives of the asset / liability studies. These asset allocations, when viewed over a long-term historical view of the capital markets, yield an expected return on assets in excess of 9%.

Exelon’s pension plan weighted average asset allocations at December 31, 2005 and 2004 and target allocation for 2005 were as follows:

			Percentage of Plan Assets at December 31,
Asset Category	Target Allocation at December 31, 2005		2005		2004
Equity securities	60	%	61	%	63	%
Debt securities	35-40		35		33
Real estate	0-5		4		4
Total			100	%	100	%

Exelon’s other postretirement benefit plan weighted average asset allocations at December 31, 2005 and 2004 and target allocation for 2005 were as follows:

			Percentage of Plan Assets at December 31,
Asset Category	Target Allocation at December 31, 2005		2005		2004
Equity securities	60-65	%	63	%	64	%
Debt securities	35-40		35		34
Real estate	—		2		2
Total			100	%	100	%

226

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Exelon’s defined benefit pension plans and postretirement welfare benefit plans do not directly hold shares of Exelon common stock.

Assumed health care cost trend rates have a significant effect on the costs reported for the health care plans. A one percentage point change in assumed health care cost trend rates would have the following effects:

Effect of a one percentage point increase in assumed health care cost trend
on total service and interest cost components	$	41
on postretirement benefit obligation		399
Effect of a one percentage point decrease in assumed health care cost trend
on total service and interest cost components		(30	)
on postretirement benefit obligation		(297	)

Estimated future benefit payments to participants in Exelon’s pension plans and postretirement welfare benefit plans as of December 31, 2005 were:

	Pension Benefits		Other Postretirement Benefits (a)
2006	$	553	$	205
2007		555		219
2008		557		231
2009		560		242
2010		568		252
2011 through 2015		3,076		1,420
Total estimated future benefits payments through 2015	$	5,869	$	2,569

(a) Estimated future benefit payments do not reflect an anticipated Federal subsidy provided through the Prescription Drug Act. The Federal subsidies to be received by Exelon in the years 2006, 2007, 2008, 2009, 2010 and from 2011 through 2015 are estimated to be $8 million, $8 million, $9 million, $10 million, $11 million and $69 million, respectively.

Exelon sponsors savings plans for the majority of its employees. The plans allow employees to contribute a portion of their pre-tax income in accordance with specified guidelines. Exelon matches a percentage of the employee contribution up to certain limits. The cost of Exelon’s matching contribution to the savings plans totaled $58 million, $57 million and $55 million in 2005, 2004 and 2003, respectively.

16. Fair Value of Financial Assets and Liabilities

Non-Derivative Financial Assets and Liabilities

Fair Value.As of December 31, 2005 and 2004, Exelon’s carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities are representative of fair value because of the short-term nature of these instruments. Fair values for long-term debt and preferred securities of subsidiaries are determined by an external valuation model which is based on conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves.

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

The carrying amounts and fair values of Exelon’s financial liabilities as of December 31, 2005 and 2004 were as follows:

		2005				2004
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	8,166	$	8,231	$	7,719	$	8,372
Long-term debt to ComEd Transitional Funding Trust and PETT (including amounts due within one year)		3,963		4,132		4,797		5,182
Long-term debt to other financing trusts		545		539		545		573
Preferred securities of subsidiaries		87		70		87		69

Credit Risk.Financial instruments that potentially subject Exelon to concentrations of credit risk consist principally of cash equivalents and customer accounts receivable. Exelon 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 Exelon’s large number of customers and, in the case of ComEd’s and PECO’s energy delivery businesses, their dispersion across many industries.

Exelon would also be exposed to credit-related losses in the event of non-performance by counterparties that issue derivative instruments. The credit exposure of derivative contracts is represented by the fair value of contracts at the reporting date. The notional amount of derivatives does not represent amounts that are exchanged by the parties and, thus, are not a measure of Exelon’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.

Interest-Rate Swaps

The fair values of Exelon’s interest-rate swaps and purchase power 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. At December 31, 2005 and 2004, Exelon had $240 million and $440 million, respectively, of notional amounts of interest-rate swaps outstanding. At December 31, 2005 and 2004, net deferred gains (losses) associated with the interest-rate swaps were as follows:

	Notional Amount		Exelon Pays	Counterparty Pays	Fair Value 12/31/05			Fair Value 12/31/04
Fair-Value Hedges
ComEd	$	240	3 Month LIBOR	6.15%	$	(1	)	$	9
			plus 1.12% –1.60%
Cash-Flow Hedges
Exelon		200	4.59% – 4.65%	3 Month LIBOR		—			2
Net Deferred Gains (Losses)					$	(1	)	$	11

Fair-Value Hedges. Exelon utilizes fixed-to-floating interest-rate swaps as a means to achieve its targeted level of variable-rate debt as a percent of total debt. At December 31, 2005, Exelon had $240 million of notional amounts of fair-value hedges outstanding. The swaps have been designated

228

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

as fair-value hedges, as defined in SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133), and, as such, changes in the fair value of the swaps are 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 are 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 is recorded immediately in earnings.

During 2004, Exelon settled interest-rate swaps in aggregate notional amounts of $485 million and recorded a net pre-tax gain of $26 million, which is being amortized as a reduction to interest expense over the remaining life of the related debt. Exelon did not have any amount excluded from the measure of effectiveness for the years ended December 31, 2005 or 2004.

Cash-Flow Hedges. Exelon utilizes interest rate derivatives to lock in interest-rate levels in anticipation of future financings. Forward-starting interest-rate swaps are designated as cash-flow hedges, as defined in SFAS No. 133 and, as such, changes in the fair value of the swaps are recorded in accumulated other comprehensive income (OCI). Any change in the fair value of the hedge as a result of ineffectiveness is recorded immediately in earnings. At December 31, 2005, Exelon did not have any notional amounts of cash-flow hedges outstanding. During 2005, Exelon settled interest-rate swaps in the aggregate notional amount of $1.8 billion, of which $325 million was the result of a forecasted transaction no longer being probable, and recorded pre-tax losses of $54 million, of which $15 million was included in other, net within Exelon’s Consolidated Statements of Income. Exelon is recording the remaining $39 million as additional interest expense over the remaining life of the related debt.

During 2004, Exelon settled $315 million of interest-rate swaps in aggregate notional amounts of and recorded net pre-tax gains of $1 million which is being amortized over the lives of the related debt. In addition, during 2004, Exelon recorded income of $0.2 million which represented the ineffective portions of changes in the fair value of cash-flow hedge positions. This amount was associated with the settlement of interest-rate swaps in December 2004 and was included in other, net on Exelon’s Consolidated Statements of Income. Exelon did not reclassify any amounts from accumulated OCI into earnings as a result of financing transactions no longer being probable during the year ended December 31, 2004.

Energy-Related Derivatives

Generation utilizes derivatives to manage the utilization of its available generating capacity and the provision of wholesale energy to its affiliates. Exelon 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. Generation’s energy contracts are accounted for under SFAS No. 133. Non-trading contracts may qualify for the normal purchases and normal sales exemption to SFAS No. 133 discussed in the “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Critical Accounting Policies and Estimates.” Those that do not meet the normal purchase and normal sales exemption are recorded as assets or liabilities on the balance sheet at fair value. Changes in the derivatives recorded at fair value are recognized in earnings unless specific hedge accounting criteria are met and they are designated as cash-flow hedges, in which case those changes are recorded in OCI, and gains and losses are recognized in earnings when the underlying

229

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

transaction occurs. Changes in the fair value of derivative contracts that do not meet the hedge criteria under SFAS No. 133 (or are not designated as such) and proprietary trading contracts are recognized in current earnings. Generation also has contracted for access to additional generation and sales to load-serving entities that are accounted for under the accrual method of accounting discussed in Note 20—Commitments and Contingencies.

At December 31, 2005, Exelon had net liabilities of $516 million on its Consolidated Balance Sheets for the fair value of energy derivatives, which included the energy derivatives discussed below. The following tables provide a summary of the fair value balances recorded by Exelon as of December 31, 2005:

December 31, 2005	Generation												Other(a) Derivatives		Exelon Energy-Related Derivatives(b)
Derivatives	Cash-Flow Hedges			Other Derivatives			Proprietary Trading			Subtotal
Current assets	$	563		$	327		$	26		$	916		$	—	$	916
Noncurrent assets		153			9			124			286			24		310
Total mark-to-market energy contract assets	$	716		$	336		$	150		$	1,202		$	24	$	1,226
Current liabilities	$	(948	)	$	(316	)	$	(18	)	$	(1,282	)	$	—	$	(1,282	)
Noncurrent liabilities		(289	)		(48	)		(123	)		(460	)		—		(460	)
Total mark-to-market energy contract liabilities	$	(1,237	)	$	(364	)	$	(141	)	$	(1,742	)	$	—	$	(1,742	)
Total mark-to-market energy contract net assets (liabilities)	$	(521	)	$	(28	)	$	9		$	(540	)	$	24	$	(516	)

(a) Other includes corporate operations, shared service entities, including Exelon Business Services Company (BSC), Enterprises and investments in synthetic fuel-producing facilities.

(b) Excludes Exelon’s interest-rate swaps.

At December 31, 2004, Exelon had net liabilities of $145 million on its Consolidated Balance Sheets for the fair value of energy derivatives, which included the energy derivatives discussed below. The following table provides a summary of the fair value balances recorded by Exelon at December 31, 2004:

December 31, 2004	Generation											Other(a) Derivatives		Exelon Energy-Related Derivatives(b)
Derivatives	Cash-Flow Hedges			Other Derivatives			Proprietary Trading		Subtotal
Current assets	$	295		$	106		$	2	$	403		$	—	$	403
Noncurrent assets		132			240			1		373			—		373
Total mark-to-market energy contract assets	$	427		$	346		$	3	$	776		$	—	$	776
Current liabilities	$	(489	)	$	(109	)	$	—	$	(598	)	$	—	$	(598	)
Noncurrent liabilities		(162	)		(161	)		—		(323	)		—		(323	)
Total mark-to-market energy contract liabilities	$	(651	)	$	(270	)	$	—	$	(921	)	$	—	$	(921	)
Total mark-to-market energy contract net assets (liabilities)	$	(224	)	$	76		$	3	$	(145	)	$	—	$	(145	)

230

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

(a) Other includes corporate operations, shared service entities, including Exelon Business Services Company (BSC), Enterprises and investments in synthetic fuel-producing facilities.

(b) Excludes Exelon’s interest-rate swaps.

Normal Operations and Hedging Activities.Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including ComEd’s and PECO’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 anticipated exposures.

Cash-Flow Hedges

The tables below provide details of effective cash-flow hedges under SFAS No. 133 included on Exelon’s Consolidated Balance Sheets as of December 31, 2005. The data in the table is indicative of the magnitude of SFAS No. 133 hedges Generation has in place; however, since under SFAS No. 133 not all derivatives are recorded in OCI, the table does not provide an all-encompassing picture of Generation’s derivatives. The tables also include a rollforward of accumulated OCI related to cash-flow hedges for the years ended December 31, 2005 and 2004, providing information about the changes in the fair value of hedges and the reclassification from OCI into earnings.

December 31, 2005	Total Cash-Flow Hedge OCI Activity, Net of Income Tax
Accumulated OCI derivative loss at January 1, 2005	$	(137	)
Changes in fair value		(533	)
Reclassifications from OCI to net income		356
Accumulated OCI derivative loss at December 31, 2005	$	(314	)
December 31, 2004	Total Cash-Flow Hedge OCI Activity, Net of Income Tax
Accumulated OCI derivative loss at January 1, 2004	$	(133	)
Changes in fair value		(312	)
Disposal of existing Boston Generating contracts		16
Reclassifications from OCI to net income		290
Exelon Energy Company opening balance		2
Accumulated OCI derivative loss at December 31, 2004	$	(137	)

At December 31, 2005, Generation had net unrealized pre-tax losses of $521 million of cash-flow hedges recorded in accumulated OCI. Based on market prices at December 31, 2005, approximately $386 million of these deferred net pre-tax unrealized losses on derivative instruments in accumulated OCI are expected to be reclassified to earnings during the next twelve months. However, the actual amount reclassified to earnings could vary due to future changes in market prices. Amounts recorded in accumulated OCI 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 three years.

231

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Generation’s cash-flow hedge activity impact to Exelon’s pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $583 million pre-tax loss, a $475 million pre-tax loss and a $273 million pre-tax loss for the years ended December 31, 2005, 2004 and 2003 respectively.

Other Derivatives

Generation enters into certain contracts that are derivatives, but do not qualify for hedge accounting under SFAS No. 133 or are not designated as cash-flow hedges. These contracts are also entered into to economically hedge and limit the market price risk associated with energy commodity prices. Changes in the fair value of these derivative contracts are recognized in current earnings. For 2005, 2004, and 2003, Exelon recognized the following net unrealized mark-to-market gains, realized mark-to-market losses and total mark-to-market gains (losses) (before income taxes) relating to mark-to-market activity of certain non-trading purchase power and sale contracts pursuant to SFAS No. 133. Mark-to-market activity on non-trading purchase power and sale contracts are reported in fuel and purchased power.

	For the Year Ended December 31,
	2005			2004			2003
Unrealized mark-to-market gains	$	110		$	181		$	207
Realized mark-to-market losses		(98	)		(183	)		(223	)
Total net mark-to-market gains (losses)	$	12		$	(2	)	$	(16	)

Proprietary Trading Activities. Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure and is subject to limits established by the Risk Management Committee. 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. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a very small portion of Generation’s overall energy marketing activities. For 2005, 2004 and 2003, Exelon recognized the following net unrealized mark-to-market gains, realized mark-to-market gains (losses) and total mark-to-market gains (before income taxes) 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 Exelon’s Consolidated Statements of Income.

	For the Year Ended December 31,
	2005			2004			2003
Unrealized mark-to-market gains (losses)	$	18		$	3		$	(3	)
Realized mark-to-market gains (losses)		(3	)		(3	)		4
Total net mark-to-market gains	$	15		$	—		$	1

Exelon Energy has entered into a limited number of energy commodity derivative contracts in connection with its service of gas customers. Prior to January 1, 2004, contracts were maintained by Exelon Energy. While the majority of these contracts qualify as normal purchases and sales or as cash-flow hedges under SFAS No. 133, $15 million was recorded as an increase to fuel expense in 2003 primarily as a result of the reversal of the 2002 mark-to-market adjustments.

Credit Risk Associated with Derivative Instruments.Exelon would be exposed to credit-related losses in the event of non-performance by counterparties that issue derivative instruments. The credit

232

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

exposure of derivatives contracts is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, 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 notional amount of derivatives does not represent amounts that are exchanged by the parties and, thus, is not a measure of Exelon’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.

Nuclear Decommissioning Trust Fund Investments

Investments as of December 31, 2005 and 2004.Exelon classifies investments in trust accounts for decommissioning nuclear plants as available-for-sale and estimates their fair value based on quoted market prices for the securities held in trust funds. These investments are held to fund Generation’s decommissioning obligation for its nuclear plants. Decommissioning expenditures are expected to occur primarily after the plants are retired. Based on current licenses and anticipated renewals, decommissioning expenditures for plants in operation are currently estimated to begin after 2029. See Note 13—Nuclear Decommissioning and Spent Fuel Storage for further information regarding the decommissioning of Generation’s nuclear plants.

The following tables show the fair values, gross unrealized gains and losses and amortized cost bases of the securities held in these trust accounts as of December 31, 2005 and 2004:

	December 31, 2005
	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
Cash and cash equivalents	$	80	$	—	$	—		$	80
Marketable equity securities		2,762		683		(32	)		3,413
U.S. Treasury obligations and direct obligations of U.S. government agencies		361		32		(6	)		387
Other debt securities		1,695		19		(9	)		1,705
Total available-for-sale securities	$	4,898	$	734	$	(47	)	$	5,585
	December 31, 2004
	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
Cash and cash equivalents	$	184	$	—	$	—		$	184
Equity securities		2,194		538		(37	)		2,695
U.S. Treasury obligations and direct obligations of U.S. government agencies		1,447		51		(4	)		1,494
Other debt securities		855		37		(3	)		889
Total available-for-sale securities	$	4,680	$	626	$	(44	)	$	5,262

The fixed-income available-for-sale securities held at December 31, 2005 have an average maturity range of seven to ten years. The cost of these securities was determined on the basis of specific identification.

233

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Impairment Evaluation in 2005.At December 31, 2005, Exelon had gross unrealized gains of $734 million and gross unrealized losses of $47 million related to the nuclear decommissioning trust fund investments. At December 31, 2004, Exelon had gross unrealized gains of $626 million and gross unrealized losses of $44 million related to the nuclear decommissioning trust fund investments. With the exception of the portion of these amounts primarily related to AmerGen and as a result of ComEd’s and PECO’s regulatory arrangements for decommissioning costs, approximately $556 million and $469 million of these net unrealized gains were recorded as an increase to regulatory liabilities as of December 31, 2005 and 2004, respectively.

Exelon evaluates decommissioning trust fund investments for other-than-temporary impairments by analyzing the historical performance, cost basis and market value of securities in unrealized loss positions in comparison to related market indices. Exelon evaluates whether certain trust fund investments are other-than-temporarily impaired based on various factors assessed in the aggregate, including the duration and severity of the impairment, the anticipated recovery of the securities and considerations of Generation’s ability and intent to hold the investments until the recovery of their cost basis. This evaluation resulted in a $2 million and $8 million impairment charge recorded in other income and deductions associated with the decommissioning trust funds of the AmerGen plants during the years ended December 31, 2005 and 2004, respectively. Also, Exelon realized $20 million and $260 million of impairment charges associated with the trust funds for the decommissioning of the former ComEd and former PECO plants during the years ended December 31, 2005 and 2004, respectively. Recognition of these impairment charges associated with the former ComEd and former PECO plants had no net income impact on Exelon’s results of operations or financial position.

Unrealized Gains and Losses.Net unrealized gains of $687 million and $582 million were included in regulatory liabilities or accumulated other comprehensive income in Exelon’s Consolidated Balance Sheets at December 31, 2005 and 2004, respectively.

The following table provides information regarding available-for-sale securities held in nuclear decommissioning trust funds in an unrealized loss position that were not considered other-than-temporarily impaired. The following tables show 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, 2005 and 2004.

	December 31, 2005
	Less than 12 months					12 months or more					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
Marketable equity securities	$	345	$	(23	)	$	69	$	(9	)	$	414	$	(32	)
U.S. Treasury obligations and direct obligations of U.S. government agencies		433		(5	)		28		(1	)		461		(6	)
Other debt securities		275		(5	)		73		(4	)		348		(9	)
Total	$	1,053	$	(33	)	$	170	$	(14	)	$	1,223	$	(47	)

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

	December 31, 2004
	Less than 12 months					12 months or more					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
Marketable equity securities	$	197	$	(16	)	$	278	$	(21	)	$	475	$	(37	)
U.S. Treasury obligations and direct obligations of U.S. government agencies		207		(2	)		68		(2	)		275		(4	)
Other debt securities		182		(2	)		22		(1	)		204		(3	)
Total	$	586	$	(20	)	$	368	$	(24	)	$	954	$	(44	)

Exelon evaluates the historical performance, cost basis and market value of securities in unrealized loss positions in comparison to related market indices to assess whether or not the securities are other-than-temporarily impaired. Exelon concluded that the trending of the related market indices, the historical performance of these securities over a long-term time horizon and the level of insignificance of the unrealized loss as a percentage of the cost of the individual securities indicates that the securities are not other-than-temporarily impaired.

Sale of Nuclear Decommissioning Trust Fund Investments.Proceeds from the sale of decommissioning trust fund investments and gross realized gains and losses on those sales for the years ended December 31, 2005, 2004 and 2003 were as follows:

	For the Years Ended December 31,
	2005			2004			2003
Proceeds from sales	$	5,274		$	2,320		$	2,341
Gross realized gains		130			115			219
Gross realized losses		(81	)		(43	)		(235	)

17. Preferred Securities

At December 31, 2005 and 2004, Exelon was authorized to issue up to 100,000,000 shares of preferred stock, none of which was outstanding.

Preferred and Preference Stock of Subsidiaries

At December 31, 2005 and 2004, ComEd prior preferred stock and ComEd cumulative preference stock consisted of 850,000 shares and 6,810,451 shares authorized, respectively, none of which was outstanding.

At December 31, 2005 and 2004, cumulative preferred stock of PECO, no par value, consisted of 15,000,000 shares authorized and the outstanding amounts set forth below. Shares of preferred stock have full voting rights, including the right to cumulate votes in the election of directors.

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(Dollars in millions, except per share data unless otherwise noted)

	Current Redemption Price(a)		December 31,
			2005	2004	2005		2004
			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
Total preferred stock			874,720	874,720	$	87	$	87

^(a) Redeemable, at the option of PECO, at the indicated dollar amounts per share, plus accrued dividends.

18. Common Stock

At December 31, 2005 and 2004, Exelon’s common stock without par value consisted of 2,000,000,000 and 1,200,000,000 shares authorized, respectively, and 666,369,787 and 664,187,996 shares outstanding, respectively.

Stock Split

On January 27, 2004, the Board of Directors of Exelon approved a 2-for-1 stock split of Exelon’s common stock. The distribution date was May 5, 2004. The share and per-share amounts have been adjusted for all periods presented to reflect the stock split.

Share Repurchases

Share Repurchase Program. In April 2004, Exelon’s Board of Directors approved a discretionary share repurchase program that allows Exelon to repurchase shares of its common stock on a periodic basis in the open market. The share repurchase program is intended to mitigate, in part, the dilutive effect of shares issued under Exelon’s employee stock option plan and Exelon’s Employee Stock Purchase Plan (ESPP). The aggregate value of the shares of common stock repurchased pursuant to the program cannot exceed the economic benefit received after January 1, 2004 due to stock option exercises and share purchases pursuant to Exelon’s ESPP. The economic benefit consists of the direct cash proceeds from purchases of stock and the tax benefits associated with exercises of stock options. The share repurchase program has no specified limit on the number of shares that may be repurchased and no specified termination date. Any shares repurchased are held as treasury shares unless cancelled or reissued at the discretion of Exelon’s management. Treasury shares are recorded at cost. As of December 31, 2005, 9.1 million shares of common stock have been purchased under the share repurchase program for $429 million. During 2005 and 2004, 6.8 million shares, and 2.3 million shares, respectively, of common stock were purchased under the share repurchase program for $354 million and $75 million, respectively.

Other Share Repurchases. During both the first quarter of 2005 and the fourth quarter of 2004, Exelon repurchased 0.2 million shares of common stock from a retired executive for $8 million and $7 million, respectively. These shares are held as treasury shares and recorded at cost.

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(Dollars in millions, except per share data unless otherwise noted)

Stock-Based Compensation Plans

Exelon maintains Long-Term Incentive Plans (LTIPs) for certain full-time salaried employees. The types of long-term incentive awards that have been granted under the LTIPs are non-qualified options to purchase shares of Exelon’s common stock and common stock awards. At December 31, 2005, there were options for approximately 27,909,780 shares remaining for issuance under the LTIPs.

The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. Options granted under the LTIPs become exercisable upon attainment of a target share value and/or specified vesting date. All options expire 10 years from the date of grant. The vesting period of options outstanding as of December 31, 2005 generally ranged from 3 years to 4 years.

Information with respect to the LTIPs at December 31, 2005 and changes for the three years then ended, is as follows:

	Shares 2005		Weighted Average Exercise Price (per share) 2005		Shares 2004		Weighted Average Exercise Price (per share) 2004		Shares 2003		Weighted Average Exercise Price (per share) 2003
Balance at January 1	25,205,285		$	26.78	28,307,386		$	24.51	31,773,980		$	22.90
Options granted/assumed	5,298,750			42.89	6,994,288			32.57	6,346,400			24.85
Options exercised	(8,352,772	)		25.08	(9,373,662	)		24.20	(9,017,390	)		19.03
Options canceled	(476,993	)		33.23	(722,727	)		27.34	(795,604	)		25.09
Balance at December 31	21,674,270		$	31.23	25,205,285		$	26.78	28,307,386		$	24.51
Exercisable at December 31	9,673,986		$	26.03	13,097,192		$	24.88	18,032,696		$	24.33
Weighted average fair value of options granted during year			$	6.33			$	4.79			$	5.52

The fair value of each option is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used for grants in 2005, 2004 and 2003, respectively:

	2005	2004	2003
Dividend yield	3.6%	3.3%	3.3%
Expected volatility	18.1%	19.7%	30.5%
Risk-free interest rate	3.83%	3.25%	3.0%
Expected life (years)	6.25	5.0	5.0

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(Dollars in millions, except per share data unless otherwise noted)

At December 31, 2005, the options outstanding, based on ranges of exercise prices, were as follows:

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number Outstanding	Weighted Average Remaining Contractual Life (years)	Weighted Average Exercise Price		Number Exercisable	Weighted Average Exercise Price
$9.37-$14.06	225,747	1.4	$	11.82	225,747	$	11.82
$14.06-$18.74	313,946	3.8		18.28	313,946		18.28
$18.74-$23.43	1,553,824	3.3		19.58	1,553,824		19.58
$23.43-$28.11	5,683,692	6.4		24.40	3,339,492		24.09
$28.11-$32.80	8,109,936	6.9		31.68	3,647,752		30.63
$32.80-$37.48	632,875	5.7		33.85	514,075		33.91
$37.48-$46.85	5,154,250	9.0		42.89	79,150		42.85
Total	21,674,270	6.9	$	31.23	9,673,986	$	26.03

Exelon common share awards of 871,410, 1,813,874 and 901,958 shares were granted under Exelon’s LTIPs and board compensation plans during 2005, 2004 and 2003, respectively. Compensation costs related to these awards are accrued and expensed over the vesting period, typically up to 5 years from the grant date. Exelon recognized stock-based compensation expense of $57 million, $65 million and $31 million during 2005, 2004 and 2003, respectively. At December 31, 2005 and 2004, Exelon had a liability of $100 million and $81 million, respectively, related to outstanding awards not yet settled through cash payments or share issuances.

Exelon also has an ESPP. The purpose of the ESPP is to provide employees of Exelon and its subsidiary companies the right to purchase shares of Exelon’s common stock at below-market prices. A total of 5,357,745 shares of Exelon��s common stock have been reserved for issuance under the ESPP. Employees’ purchases are limited to no more than 155 shares per quarter and no more than $25,000 in fair market value in any plan year. Employees purchased 259,072, 309,492, and 418,652 shares of Exelon common stock under the ESPP in 2005, 2004 and 2003, respectively.

Undistributed Losses of Equity Method Investments

Exelon had undistributed losses of equity method investments of $107 million and $57 million at December 31, 2005 and 2004, respectively.

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(Dollars in millions, except per share data unless otherwise noted)

19. Earnings Per Share

Diluted earnings per share are calculated by dividing net income by the weighted average number of shares of common stock outstanding, including shares to be issued upon exercise of stock options outstanding under Exelon’s stock option plans considered to be common stock equivalents. The following table sets forth the computation of basic and diluted earnings per share and shows the effect of these stock options on the weighted average number of shares outstanding used in calculating diluted earnings per share:

	2005			2004			2003
Income from continuing operations	$	951		$	1,870		$	892
Gain (loss) from discontinued operations		14			(29	)		(99	)
Income before cumulative effect of changes in accounting principles		965			1,841			793
Cumulative effect of changes in accounting principles		(42	)		23			112
Net income	$	923		$	1,864		$	905
Average common shares outstanding—basic		669			661			651
Assumed exercise of stock options		7			8			6
Average common shares outstanding—diluted		676			669			657
Earnings per average common share—Basic:
Income from continuing operations	$	1.42		$	2.83		$	1.37
Income (loss) from discontinued operations		0.02			(0.04	)		(0.15	)
Income before cumulative effect of changes in accounting principles		1.44			2.79			1.22
Cumulative effect of changes in accounting principles		(0.06	)		0.03			0.17
Net income	$	1.38		$	2.82		$	1.39
Earnings per average common share—Diluted:
Income from continuing operations	$	1.40		$	2.79		$	1.36
Income (loss) from discontinued operations		0.02			(0.04	)		(0.15	)
Income before cumulative effect of changes in accounting principles		1.42			2.75			1.21
Cumulative effect of changes in accounting principles		(0.06	)		0.03			0.17
Net income	$	1.36		$	2.78		$	1.38

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately nine million for 2003. There were no stock options excluded for 2005 or 2004.

20. Commitments and Contingencies

Nuclear Insurance

The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. As of December 31, 2005, the limit is $10.76 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. Through its subsidiaries, Exelon carries the maximum available commercial insurance of $300 million for each operating site and the remaining $10.46 billion is provided through mandatory participation in a

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(Dollars in millions, except per share data unless otherwise noted)

financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed a maximum charge per reactor per incident. The maximum assessment for all nuclear operators per reactor per incident (including a 5% surcharge) is $100.6 million, payable at no more than $15 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 was extended to December 31, 2025 under the Energy Act Policy.

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 $176 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 insured plants, 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 extended, 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. Generation’s maximum share of any assessment is $47 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 extended, 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 its insured losses, Exelon is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon’s financial condition, results of operations and liquidity.

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(Dollars in millions, except per share data unless otherwise noted)

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 purchase 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 purchase power agreements (PPAs). These agreements are firm commitments related to power generation of specific generation plants and/or are dispatchable in nature. Generation enters into purchase power agreements 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, 2005, Generation had long-term commitments, relating to the purchase from and sale to unaffiliated utilities and others of energy, capacity and transmission rights as indicated in the following tables:

	Net Capacity Purchases (a)		Power Only Sales		Power Only Purchases		Transmission Rights Purchases
2006	$	616	$	2,783	$	1,508	$	7
2007		527		947		491		3
2008		460		80		194		—
2009		434		18		194		—
2010		436		19		194		—
Thereafter		3,391		—		355		—
Total	$	5,864	$	3,847	$	2,936	$	10

^(a) Net capacity purchases include tolling agreements that are accounted for as operating leases. Amounts presented in the commitments represent Generation’s expected payments under these arrangements at December 31, 2005. Expected payments include certain capacity charges which are contingent on plant availability.

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Fuel Purchase Obligations

In addition to Generation’s energy commitments described above, Exelon has commitments to purchase fuel supplies for nuclear and fossil generation. As of December 31, 2005, these commitments were as follows:

	Total		Expiration within
			2006		2007-2008		2009-2010		2011 and beyond
Fuel purchase agreements	$	4,299	$	754	$	1,235	$	933	$	1,377

Commercial Commitments

Exelon’s commercial commitments as of December 31, 2005, representing commitments potentially triggered by future events, were as follows:

	Expiration within
	Total		2006		2007-2008		2009-2010		2011 and beyond
Letters of credit (non-debt)(a)	$	116	$	116	$	—	$	—	$	—
Letters of credit (long-term debt)—interest coverage(b)		15		15		—		—		—
Surety bonds(c)		296		132		66		—		98
Performance guarantees(d)		201		—		—		—		201
Energy marketing contract guarantees(e)		208		131		—		—		77
Nuclear insurance premiums(f)		1,710		—		—		—		1,710
Lease guarantees(g)		9		—		—		—		9
Midwest Generation Capacity Reservation Agreement guarantee(h)		25		4		8		8		5
Exelon New England guarantees(i)		14		—		—		—		14
Other		13		13		—		—		—
Total commercial commitments	$	2,607	$	411	$	74	$	8	$	2,114

(a) Letters of credit (non-debt)—Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties. As of December 31, 2005, Exelon had $116 million of outstanding letters of credit (non-debt) issued under its $1.5 billion credit agreements. Guarantees of $20 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 $520 million is reflected in long-term debt in Exelon’s Consolidated Balance Sheet.

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

(d) Performance guarantees—Guarantees issued to ensure execution under specific contracts.

(e) Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts.

(f) 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.

(g) Lease guarantees—Guarantees issued to ensure payments on building leases.

(h) 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 has agreed to reimburse Chicago for any nonperformance by Midwest Generation under the Capacity Reservation Agreement. Under FIN 45, $3 million is included as a liability on Exelon’s Consolidated Balance Sheets at December 31, 2005.

(i) Exelon New England guarantees—Mystic Development LLC (Mystic), a former affiliate of Exelon New England, has a long-term agreement through January 2020 with Distrigas of Massachusetts Corporation (Distrigas) for gas supply, primarily for

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(Dollars in millions, except per share data unless otherwise noted)

the Boston Generating units. Under the agreement, gas purchase prices from Distrigas are indexed to the New England gas markets. Exelon New England has guaranteed Mystic’s financial obligations to Distrigas under the long-term supply agreement. Exelon New England’s guarantee to Distrigas remained in effect following the transfer of ownership interest in Boston Generating in May 2004. Under FIN 45, approximately $14 million is included as a liability within the Consolidated Balance Sheets of Exelon as of December 31, 2005 related to this guarantee. The terms of the guarantee do not limit the potential future payments that Exelon New England could be required to make under the guarantee. Other guarantees associated with Exelon New England total less than $1 million.

Environmental Issues

General.Exelon’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, Exelon, through its subsidiaries, is generally liable for the costs of remediating environmental contamination of property now or formerly owned by Exelon and of property contaminated by hazardous substances generated by Exelon. Exelon’s subsidiaries own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. ComEd and PECO have identified 42 and 27 sites, respectively, where former manufactured gas plant (MGP) activities have or may have resulted in actual site contamination. Of these 42 sites identified by ComEd, the Illinois Environmental Protection Agency has approved the clean up of six sites and of the 27 sites identified by PECO, the Pennsylvania Department of Environmental Protection has approved the cleanup of nine sites. Of the remaining sites identified by ComEd and PECO, 22 and 11 sites, respectively, are currently under some degree of active study and/or remediation. In addition, Exelon’s subsidiaries are 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, 2005 and December 31, 2004, Exelon had accrued the following amounts for environmental liabilities:

	December 31, 2005			December 31, 2004
Total environmental investigation and remediation reserve	$	128	(a)	$	124	(b)
Portion of total related to MGP investigation and remediation		89			96

^(a) Includes $89 million that has been recorded on a discounted basis, reflecting a discount rate of 4.0%. Estimate before the effects of discounting was $102 million, which reflects an inflation rate of 2.3%.

^(b) Includes $96 million that has been recorded on a discounted basis, reflecting a discount rate of 4.3%. Estimate before the effects of discounting was $109 million, which reflects an inflation rate of 2.3%.

As of December 31, 2005, Exelon anticipates that payments related to the discounted environmental investigation and remediation costs, disclosed below on an undiscounted basis, will be:

2006	$	12
2007		22
2008		18
2009		19
2010		10
Remaining years		21
Total payments	$	102

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(Dollars in millions, except per share data unless otherwise noted)

Exelon cannot reasonably estimate whether it will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by Exelon, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. However, pursuant to a PAPUC order, PECO is currently recovering through regulated gas rates costs associated with the remediation of the MGP sites. See Note 21—Supplemental Financial Information for further information regarding regulatory assets and liabilities.

Section 316(b) of the Clean Water Act.In July 2004, the EPA issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. This rule establishes national requirements for reducing the adverse environmental impacts from the entrainment and impingement of aquatic organisms at existing power plants. The rule identifies particular standards of performance with respect to entrainment and impingement and requires each facility to monitor and validate this performance in future years. The requirements will be implemented through state-level National Pollutant Discharge Elimination System (NPDES) permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g. cooling towers) are potentially most affected. Those facilities are Clinton, Cromby, Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, New Boston, Oyster Creek, Peach Bottom, Quad Cities and Salem. Generation is currently evaluating compliance options at its affected plants. At this time, Generation cannot estimate the effect that compliance with the Phase II rule requirements will have on the operation of its generating facilities and its future results of operations, financial condition and cash flows. There are many factors to be considered and evaluated to determine how Generation will comply with the Phase II rule requirements and the extent to which such compliance may result in financial and operational impacts. The considerations and evaluations include, but are not limited to obtaining clarifying interpretations of the requirements from state regulators, resolving outstanding litigation proceedings concerning the requirements, completing studies to establish biological baselines for each facility and performing environmental and economic cost benefit evaluations of the potential compliance alternatives in accordance with the requirements.

In a pre-draft permit dated May 13, 2005 and a draft permit issued on July 19, 2005, as part of the pending National Pollution Discharge Elimination System permit renewal process for Oyster Creek, the NJDEP preliminarily determined that closed-cycle cooling and environmental restoration are the only viable compliance options for Section 316(b) compliance at Oyster Creek. AmerGen has not made a determination regarding how it will demonstrate compliance with the Section 316(b) regulations, but believes that other compliance options under the final Phase II rule are viable and will be analyzed as part of the plant’s comprehensive demonstration study.

In June 2001, the NJDEP issued a renewed NDPES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised PSEG in a letter dated July 12, 2004 that it strongly recommended reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG submitted an application for a renewal of the permit on February 1, 2006. In the permit renewal application, PSEG analyzed closed-cycle cooling and other options and demonstrated that the continuation of the Estuary Enhancement Program, an extensive environmental restoration program at Salem, is the best technology to meet the Section 316(b) requirements. If application of the Section 316(b) regulations ultimately requires the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, Exelon’s share of the total cost of the retrofit and any resulting interim replacement power would likely be in excess of $500 million and could result in increased depreciation expense related to the retrofit investment.

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(Dollars in millions, except per share data unless otherwise noted)

Nuclear Generating Station Groundwater.On December 16, 2005, the Illinois Environmental Protection Agency issued a Violation Notice to Generation alleging that the company had violated state groundwater standards due to a discharge of liquid tritium from a line at the Braidwood Nuclear Generating Station. As of December 31, 2005, Exelon recorded a reserve of $7 million (pre-tax) for this matter, which Exelon deems adequate to cover the costs of remediation and potential related corrective measures. See Note 25—Subsequent Events for further details of this and similar matters.

Cotter Corporation.The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. 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 any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. 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 the anticipated remediation strategy for the site range up to $22 million. Once a remedy is selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of the liability.

Voluntary Greenhouse Gas Emissions Reductions. Exelon announced on May 6, 2005 that it has established a voluntary goal to reduce its greenhouse gas (GHG) emissions by eight percent from 2001 levels by the end of 2008. The eight percent reduction goal represents a decrease of an estimated 1.3 million metric tons of GHG emissions. Exelon will incorporate recognition of GHG emissions and their potential cost into its business analyses as a means to promote internal investment in climate-reducing activities. Exelon made this pledge under the U.S. Environmental Protection Agency’s Climate Leaders program, a voluntary industry-government partnership addressing climate change. Exelon believes that its planned greenhouse gas management efforts, including increased use of renewable energy, its current energy efficiency initiatives and its efforts in the areas of carbon sequestration, will allow it to achieve this goal. The anticipated cost of achieving the voluntary GHG emissions reduction goal will not have a material effect on Exelon’s future results of operations, financial condition or cash flows.

Leases

Minimum future operating lease payments, including lease payments for vehicles, real estate, computers, rail cars and office equipment, as of December 31, 2005 were:

2006	$	55
2007		55
2008		53
2009		48
2010		44
Remaining years		511
Total minimum future lease payments	$	766	(a)

(a) Excludes Generation’s tolling agreements that are accounted for as operating leases and are reflected as net capacity purchases in the energy commitments table above.

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(Dollars in millions, except per share data unless otherwise noted)

Exelon’s rental expense under operating leases totaled $68 million, $64 million and $57 million in 2005, 2004, and 2003, respectively. For information regarding Exelon’s capital lease obligations, see Note 11—Long Term Debt.

Litigation

PJM Billing Dispute.In December 2004, Exelon filed a complaint against PJM and PPL Electric with the FERC alleging that PJM had overcharged Exelon from April 1998 through May 2003 as a result of a billing error. Specifically, the complaint alleges that PJM mistakenly identified PPL Electric’s Elroy substation transformer as belonging to Exelon and that, as a consequence, during times of congestion, Exelon’s bills for transmission congestion from PJM erroneously reflected energy that PPL Electric took from the Elroy substation and used to serve PPL Electric’s load. The complaint requested the FERC, among other things, to direct PPL Electric to refund to PJM $39.1 million, plus interest of approximately $8 million, and for PJM to refund these same amounts to Exelon.

On September 14, 2005, Exelon and PPL filed a proposed settlement of this matter with the FERC. If the settlement is approved by the FERC, Exelon will receive a total of $40.5 million, plus interest, over the next four years from two funding sources: (a) $33 million from PPL Electric and (b) $7.5 million from PJM market participants. It is anticipated that approximately 75% and 25% of the proposed settlement will be received by Generation and PECO, respectively. Both charges will be collected and paid by PJM over a four-year period following FERC approval of the settlement with interest on the unpaid principal accruing over the collection and payment period. As Exelon is a market participant in PJM, if this settlement is approved by the FERC, the net amount of the settlement to be received by Exelon will be reduced by Exelon’s portion of the $7.5 million described above.

Pending FERC approval of the proposed settlement, Exelon has not recorded any receivables associated with this matter.

Asbestos Personal Injury Claims.Like many other industrial companies, Generation is a defendant in personal injury actions related to asbestos exposure in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The vast majority of these asbestos-related bodily injury claims allege a variety of lung-related diseases based on alleged exposure to asbestos by former third-party contractors involved in the original construction or maintenance of the facilities. The construction of these facilities primarily occurred between 1950 and 1975. Generation does not have significant asbestos-related bodily injury claims occurring after 1980.

As part of the 2001 restructuring in which Generation purchased ComEd’s and PECO’s energy-producing facilities, Generation assumed all of ComEd’s and PECO’s current and future benefits and liabilities associated with these facilities. Based on the receipt of asbestos-related bodily injury claims during 2002, 2003 and 2004, where previously an insignificant number of claims were received and corresponding expenses were recorded, Generation engaged independent actuaries to determine if a reasonable estimate of future losses could be made based on historical claims data and other available information. Based on the currently available volume and diversity of historical claim and payment data, the actuaries determined that a reasonable estimate could be prepared and, accordingly, Generation engaged the actuaries to calculate an estimate of future losses. In the second quarter of 2005, based on the actuaries’ analyses, management’s review of current and expected losses and the view of counsel regarding the assumptions used in estimating the future losses, Exelon recorded an

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(Dollars in millions, except per share data unless otherwise noted)

undiscounted $43 million pre-tax charge for its estimated portion of all estimated future asbestos-related personal injury claims estimated to be presented through 2030. This amount does not include estimated legal costs associated with handling these matters, which could be material. Exelon management determined that it was not reasonable to estimate future asbestos-related personal injury claims past 2030 based on only three years of historical claims data and the significant amount of judgment required to estimate this liability. In calculating future losses, management and the actuaries made various assumptions, including, but not limited to, the overall number of future claims estimated through the use of actuarial models, Exelon’s estimated portion of future settlements and obligations, the distribution of exposure sites, the anticipated future mix of diseases that relate to asbestos exposure and the anticipated levels of awards made to plaintiffs. Exelon’s recent history of successfully defending itself in court cases for asbestos-related bodily injury claims was qualitatively considered in determining this estimate.

The amounts recorded by Exelon for estimated future asbestos-related bodily injury claims are based upon known facts at the time the report was prepared. Projecting future events, such as the number of new claims to be filed each year and the average cost of disposing of claims, as well as the numerous uncertainties surrounding asbestos-related litigation in the United States, could cause the actual costs to be higher or lower than projected. While it is not possible to predict the ultimate outcome of the asbestos-related claims and settlements, management believes, after consultation with counsel, that resolution of these matters is not expected to have a material adverse effect on Exelon’s results of operations and financial position. Management cautions, however, that these estimates for asbestos-related bodily injury cases and settlements are difficult to predict and may be influenced by many factors. Accordingly, these matters, if resolved in a manner different from the estimate, could have a material effect on Exelon’s results of operations, financial position and cash flow.

The $43 million pre-tax charge was recorded as part of operating and maintenance expense on Exelon’s Consolidated Statements of Income in 2005 and reduced net income by $27 million. At December 31, 2005 and 2004, Exelon had approximately $50 million and $10 million, respectively, reserved in total for asbestos-related bodily injury claims. As of December 31, 2005, approximately $9 million of this amount relates to 120 open claims presented to Generation, while the remaining $41 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2030 based on actuarial assumptions and analysis. Exelon plans to obtain annual updates of the estimate of future losses. On a quarterly basis, Exelon monitors actual experience against the number of forecasted claims to be received and expected claim payments.

Oil Spill Liability Trust Fund Claim. In December 2004, the two Salem nuclear generation units were taken offline due to an oil spill from a tanker in the Delaware River near the facilities. The units, which draw water from the river for cooling purposes, were taken offline for approximately two weeks to avoid intake of the spilled oil, resulting in lost sales from the plant. Generation and PSEG have filed a joint claim for losses and damages with the Oil Spill Liability Trust Fund. As this matter represents a contingent gain, Generation has recorded no income resulting from this claim. However, Generation’s management believes it is reasonably possible that damages and losses will be recovered and that Generation’s portion of the estimated proceeds arising from the claim will be approximately $25 million. Exelon expects this matter to be resolved in 2006.

Real Estate Tax Appeals.PECO and Generation each have been challenging real estate taxes assessed on nuclear plants. 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),

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

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 2004, also regarding the valuation of its Limerick and Peach Bottom plants, Quad Cities Station (Rock Island County, IL), Three Mile Island Nuclear Station (Dauphin County, PA) (TMI), Oyster Creek Station (Forked River, NJ) and LaSalle County Station (Seneca, IL). PECO and Generation have reached settlements with the taxing authorities over the Limerick real estate assessments for 1998 and 1999. Pursuant to the settlement agreement, all Limerick tax appeals were dismissed by the state court, PECO has agreed to an additional payment of approximately $3 million for the two PURTA years and Generation has agreed to make additional payments in lieu of taxes for years 2005 through 2008. As a result of the Limerick settlement, Exelon reduced its real estate tax reserve balance by $6 million in the first quarter of 2005. In addition, Generation reached a settlement with the taxing authorities over the TMI real estate assessment, which has been approved by the state court. As a result of the TMI settlement, Exelon reduced its real estate tax reserve balance by $6 million in the first quarter of 2005. Generation reached an agreement with the taxing authorities for all years under appeal for the Quad Cities station and the court approved the agreement on December 9, 2005. Generation also recently reached an agreement with the taxing authorities for all years under appeal for the Oyster Creek station and an order implementing Oyster Creek’s property tax settlement was entered on December 16, 2005. In addition, on December 22, 2005, Generation reached an agreement for the 2005 tax year with the taxing authorities for LaSalle County Station, and is working towards court approval by the end of the first quarter of 2006.

Exelon believes its reserve balances for other exposures associated with real estate taxes as of December 31, 2005 and 2004 reflect the probable expected outcome of the litigation and appeals proceedings in accordance with SFAS No. 5. The ultimate outcome of such matters, however, could result in unfavorable or favorable adjustments to the consolidated financial statements of Exelon and such adjustments could be material.

ComEd Rate Case. As part of its current rate case, ComEd has requested recovery of amounts, which have previously been recorded as expense. Specifically, ComEd has requested recovery through rates of the $104 million (pre-tax) net loss on extinguishment of long-term debt as part of ComEd’s 2004 Accelerated Liability Management Plan. Additionally, ComEd is seeking a new rider to recover environmental clean up costs that will occur after the transition period is over. These amounts are currently included in Exelon’s liability for environmental investigation and remediation costs, which totaled $128 million as of December 31, 2005. As discussed in Note 4—Regulatory Issues, ComEd anticipates receiving a final order associated with the rate case during the third quarter of 2006. If the order affirms these requests, Exelon will recognize a one-time benefit to reverse these prior charges.

Reverse-Employment Discrimination Claim. On April 4, 2005, one employee of PECO and four employees of Generation commenced suit in the United States District Court for the Eastern District of Pennsylvania, alleging that they were subjected to a practice of reverse-employment discrimination which denied promotional opportunities to older white male employees, purportedly in violation of various Federal antidiscrimination statutes and the Pennsylvania Human Relations Act. The plaintiffs filed the action individually and on behalf of a putative class that includes all white males currently or previously employed with any Exelon companies in the United States who were at least 40 years old on April 4, 2003 and who either applied for or were eligible to apply for supervisory positions in March 2003 and thereafter, continuing to the present day, and were not selected for these positions. The

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Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

defendants have filed an answer denying all liability and are proceeding with discovery pertaining to the class allegations and the named plaintiffs’ individual claims. In December 2005, the Court ordered the case to be suspended until April 3, 2006 while the parties attempt to resolve this matter through non-binding mediation. As this case is in the early stages, Exelon cannot predict the outcome; however, Exelon does not expect this claim to have a material adverse effect on Exelon’s financial condition, results of operations or cash flows.

General. Exelon is involved in various other litigation matters that are being defended and handled in the ordinary course of business. Exelon maintains accruals for such costs that are probable of being incurred and subject to reasonable estimation. The ultimate outcomes of such matters, as well as the matters discussed above, are uncertain and may have a material adverse effect on Exelon’s financial condition, results of operations or cash flows.

Capital Commitments

Generation has a 72% interest in SCEP, which owns a peaking facility in Chicago. SCEP is obligated to make total equity distributions of $46 million through 2022 to the party, which is not affiliated with Exelon, that owns the remaining 28% interest. This amount reflects a return of that party’s investment in SCEP. 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 28% interest in SCEP. Additionally, Generation may be required to purchase the remaining 28% interest upon the occurrence of certain events, including Generation’s failure to maintain an investment grade rating. The total long-term liability related to SCEP was $46 million and $49 million as of December 31, 2005 and 2004, respectively.

Fund Transfer Restrictions

Under applicable law, Exelon may borrow or receive any extension of credit or indemnity from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool. Additionally, under applicable Federal law, 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, among other things, “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, 2005 and 2004, Exelon had retained earnings of $3.2 billion and $3.4 billion, respectively, which included ComEd retained earnings (deficit) of $(81) million, consisting of $1,099 million of retained earnings appropriated for future dividends offset by unappropriated deficit of $(1,180) million, and $1,102 million (all which has been appropriated for future dividends at December 31, 2004), PECO retained earnings of $649 million and $607 million, and Generation undistributed earnings of $1,002 million and $761 million, respectively. At December 31, 2005 and 2004, Exelon’s common equity to total capitalization ratio was 39% and 41%, respectively.

Jointly Owned Electric Utility Plant

On January 28, 2004, the NRC issued a letter requesting PSEG to conduct a review of its Salem facility, of which Generation owns 42.59%, to assess the workplace environment for raising and addressing safety issues. PSEG responded to the letter on February 28, 2004 and had independent assessments of the work environment at both facilities performed. Assessment results were provided

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Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

to the NRC in May 2004. The assessments concluded that Salem was safe for continued operation, but also identified issues that need to be addressed. At an NRC public meeting on June 16, 2004, PSEG outlined its action plans to address these issues, which focus on safety conscious work environment, the corrective action program and work management. A letter documenting these plans and commitments was sent to the NRC on June 25, 2004. PSEG provided the NRC a report of its progress and the progress of its actions to resolve identified issues at public meetings in 2004 and 2005. PSEG continues to publish the metrics that demonstrate performance that commenced in the fourth quarter of 2004.

Income Taxes

Refund Claims.ComEd and PECO have entered into several agreements with a tax consultant related to the filing of refund claims with the IRS. ComEd and PECO previously made refundable prepayments to the tax consultants of $11 million and $5 million, respectively. The fees for these agreements are contingent upon a successful outcome of the claims and are based upon a percentage of the refunds recovered from the IRS, if any. The ultimate net cash outflows to ComEd and 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 ComEd and PECO. A portion of ComEd’s tax benefits, including any associated interest for periods prior to the PECO / Unicom Merger, would be recorded as a reduction of goodwill pursuant to a reallocation of the PECO / Unicom Merger purchase price. Exelon cannot predict the timing of the final resolution of these refund claims.

In 2004, the IRS granted preliminary approval for one of ComEd’s refund claims and final approval was obtained in the first quarter of 2005. The refund and associated interest have been recorded in the consolidated financial statements. Approximately $14 million of tax and interest benefit received in the second quarter of 2005 has been reflected in the consolidated financial statements of which $12 million ($9 million after tax) was recorded to goodwill under the provisions of EITF Issue 93-7, “Uncertainties Related to Income Taxes in a Purchase Business Combination.” As a result, ComEd recorded consulting expenses of $5 million (pre-tax) in 2004.

Based on negotiations with the IRS during the first half of 2005, PECO believed it would receive a tax refund related to one of its claims and recorded a $6 million (pre-tax) charge related to expected consulting charges through the second quarter of 2005. However, as the result of a recent unfavorable tax court decision involving another utility related to a similar type of refund claim, PECO no longer believes payment of the consulting fees is probable and reversed the $6 million (pre-tax) charge during the third quarter 2005. PECO is unable to predict the final impact of its future negotiations with the IRS on this matter.

Other Refund Claims. ComEd and PECO have filed several tax refund claims with Federal and state taxing authorities. ComEd and PECO are unable to estimate the ultimate outcome of these refund claims and will account for any amount received in the period the matters are settled with the Federal and state taxing authorities. To the extent ComEd is successful on any of its refund claims a portion of the tax and interest benefit will be recorded to goodwill under the provisions of EITF Issue 93-7, “Uncertainties Related to Income Taxes in a Purchase Business Combination.”

Other.Exelon, through its ComEd subsidiary, has taken certain tax positions, which have been disclosed to the IRS to defer the tax gain on the 1999 sale of its fossil generating assets. See Note 12—Income Taxes for further information.

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(Dollars in millions, except per share data unless otherwise noted)

21. Supplemental Financial Information

Supplemental Income Statement Information

The following tables provide additional information about Exelon’s Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003.

	For the Years Ended December 31,
	2005		2004		2003
Depreciation, amortization and accretion
Property, plant and equipment(a)	$	816	$	835	$	736
Regulatory assets		454		418		386
Nuclear fuel(b)		385		380		395
Asset retirement obligation accretion		243		210		160
Amortization of intangible assets		69		90		4
Total depreciation, amortization and accretion	$	1,967	$	1,933	$	1,681

(a) Includes amortization of capitalized software costs.

(b) Included in fuel expense in Exelon’s Consolidated Statements of Income.

	For the Years Ended December 31,
	2005		2004		2003
Taxes other than income
Utility(a)	$	477	$	439	$	439
Real estate		121		146		65	(b)
Payroll		103		95		81
Other		27		30		(15	)(c)
Total taxes other than income	$	728	$	710	$	570

(a) Municipal and state utility taxes are also recorded in revenues on Exelon’s Consolidated Statements of Income.

(b) Includes the reduction of $74 million of property tax accruals during 2003.

(c) Includes a credit of $25 million in 2003 due to a favorable settlement of coal use tax issues at ComEd related to periods prior to the PECO / Unicom Merger.

	For the Years Ended December 31,
	2005			2004			2003
Income (loss) in equity method investments
Financing trusts of ComEd and PECO(a)	$	(30	)	$	(44	)	$	—
AmerGen(b)		—			—			47
Sithe(c)		(1	)		(11	)		2
Synfuel		(104	)		(84	)		—
Affordable housing projects(d)		—			(9	)		(10	)
Communications joint ventures and other investments		1			(6	)		(6	)
Total income (loss) in equity method investments	$	(134	)	$	(154	)	$	33

(a) Financing trusts were deconsolidated as of December 31, 2003.

(b) Prior to the acquisition of British Energy’s 50% interest in December 2003.

(c) Includes losses incurred prior to Sithe’s consolidation as of March 31, 2004 and losses from Sithe’s investments in TEG and TEP prior to their sale in October 2004. See Note 3—Acquisitions and Dispositions for additional information.

(d) Prior to the sale of investments on October 15, 2004 and November 12, 2004.

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Exelon Corporation and Subsidiary Companies

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(Dollars in millions, except per share data unless otherwise noted)

	For the Years Ended December 31,
	2005			2004			2003
Other, net
Investment income	$	9		$	7		$	14
Net loss on early extinguishment of debt		—			(130	)		—
Gain on disposition of assets, net		12			111	(d)		—
Decommissioning-related activities
Decommissioning trust fund income(a)		135			194			79
Decommissioning trust fund income—AmerGen(a)		77			43			—
Other-than-temporary impairment of decommissioning trust funds		(22	)(c)		(268	)(e)		—
Regulatory offset to non-operating decommissioning-related activities (b)		(115	)		66			(79	)
Interest associated with Federal income taxes		—			—			(14	)
Impairment of investment in Sithe		—			—			(255	)
Impairment of investments and other assets		—			(14	)		(40	)
Net direct financing lease income		22			21			20
AFUDC, equity		7			4			9
Reserve for potential plant disallowance		—			—			12
Other		13			29			10
Total other, net	$	138		$	63		$	(244	)

(a) Includes investment income and net realized gains.

(b) Includes the elimination of non-operating decommissioning-related activity for those units that are subject to regulatory accounting, including the elimination of decommissioning trust fund income and other-than-temporary impairments for certain nuclear units. See Note 13—Nuclear Decommissioning and Spent Fuel Storage and Note 16—Fair Value of Financial Assets and Liabilities for more information regarding the regulatory accounting applied for certain nuclear units.

(c) Includes other-than-temporary impairments for 2005 totaling $20 million, $0 and $2 million on nuclear decommissioning trust funds for the former ComEd units, the former PECO units and AmerGen units, respectively.

(d) Includes $85 million gain on sale of Boston Generating. See Note 3—Acquisitions and Dispositions for additional information.

(e) Includes other-than-temporary impairments for 2004 totaling $255 million, $5 million and $8 million on nuclear decommissioning trust funds for the former ComEd units, the former PECO units and the AmerGen units, respectively.

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Supplemental Cash Flow Information

As a result of adopting FIN 47 as of December 31, 2005, Exelon recorded an ARC, which was capitalized as an increase to the carrying amount of long-lived assets associated with liabilities recorded for conditional AROs. Of the total ARC, $29 million resulted in a non-cash investing activity. See Note 14—Conditional ARO for additional information on the adoption of FIN 47. In addition to this non-cash activity, the following table provides additional information about Exelon’s Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003.

	For the Years Ended December 31,
	2005		2004		2003
Cash paid during the year
Interest (net of amount capitalized)	$	798	$	888	$	801
Income taxes (net of refunds)		378		205		728
Non-cash investing and financing activities
Change in asset retirement cost		251		829		—
Consolidation of the voluntary employee beneficiary association trust		34		—		—
Resolution of certain tax matters and PECO / Unicom merger severance adjustment		23		14		—
Purchase accounting estimate adjustments		11		36		59
Sale of asset		4		—		—
Disposition of Boston Generating(a)		—		102		—
Note cancelled in conjunction with the acquisition of Sithe International from Sithe		—		92		—
Consolidation of Sithe pursuant to FIN 46-R		—		85		—
Non-cash issuance of common stock		—		26		16
Issuance of note payable to acquire synthetic fuel interests		—		22		238
Capital lease obligations				1		—
Note received in connection with the sale of Sithe to Reservoir		—		—		92
Note issued to Sithe in the Exelon New England acquisition		—		—		2

(a) See Note 3—Acquisitions and Dispositions for additional information regarding the disposition of Boston Generating.

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Supplemental Balance Sheet Information

The following tables provide additional information about assets recorded within Exelon’s Consolidated Balance Sheets as of December 31, 2005 and 2004.

December 31, 2005	ComEd		PECO		Generation		Other (a)		Exelon
Investments
Equity method investments:
Direct financing leases	$	—	$	—	$	—	$	507	$	507
Financing trusts(b)		34		73		—		—		107
TEG and TEP(c)		—		—		90		—		90
Energy services and other ventures		—		2		15		—		17
Total equity method investments		34		75		105		507		721
Other investments:
Employee benefit trusts and investments		41		20		15		16		92
Total investments	$	75	$	95	$	120	$	523	$	813

(a) Other includes corporate operations, shared service entities, including BSC, Enterprises and investments in synthetic fuel-producing facilities.

(b) Includes investments in financing trusts which were not consolidated within the financial statements of Exelon at December 31, 2004 pursuant to the provisions of FIN 46-R. See Note 1—Significant Accounting Policies for further discussion of the effects of FIN 46-R.

(c) Generation acquired 49.5% interests in two facilities in Mexico on October 13, 2004. See Note 3—Acquisitions and Dispositions for further information on this transaction.

December 31, 2004	ComEd		PECO		Generation		Other (a)		Exelon
Investments
Equity method investments:
Direct financing leases	$	—	$	—	$	—	$	486	$	486
Financing trusts(b)		52		87		—		—		139
TEG and TEP(c)		—		—		79		—		79
Energy services and other ventures		—		2		10		2		14
Total equity method investments		52		89		89		488		718
Other investments:
Employee benefit trusts and investments		39		20		14		12		85
Energy services and other ventures		—		—		—		1		1
Total other investments		39		20		14		13		86
Total investments	$	91	$	109	$	103	$	501	$	804

(a) Other includes corporate operations, shared service entities, including BSC, Enterprises and investments in synthetic fuel-producing facilities.

(b) Includes investments in financing trusts which were not consolidated within the financial statements of Exelon at December 31, 2004 pursuant to the provisions of FIN 46-R. See Note 1—Significant Accounting Policies for further discussion of the effects of FIN 46-R.

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(Dollars in millions, except per share data unless otherwise noted)

(c) Generation acquired 49.5% interests in two facilities in Mexico on October 13, 2004. See Note 3—Acquisitions and Dispositions for further information on this transaction.

Like-Kind Exchange Transaction.Prior to the PECO / Unicom Merger, UII, LLC (formerly Unicom Investments, Inc.) (UII), a wholly owned subsidiary of Exelon, entered into a like-kind exchange transaction pursuant to which approximately $1.6 billion was invested in passive generating station leases with two separate entities unrelated to Exelon. The generating stations were leased back to such entities as part of the transaction. For financial accounting purposes, the investments are accounted for as direct financing lease investments. UII holds the leasehold interests in the generating stations in several separate bankruptcy remote, special purpose companies it directly or indirectly wholly owns. Under the terms of the lease agreements, UII received a prepayment of $1.2 billion in the fourth quarter of 2000, which reduced the investment in the lease. The remaining payments are payable at the end of the thirty-year lease and there are no minimum scheduled lease payments to be received over the next five years. The components of the net investment in the direct financing leases were as follows:

	December 31,
	2005		2004
Total minimum lease payments	$	1,492	$	1,492
Less: unearned income		985		1,006
Net investment in direct financing leases	$	507	$	486

	December 31,
	2005		2004
Other deferred debits and other assets
Intangible assets(a)	$	177	$	804
Long-term prepaid state income taxes(b)		192		201
Long-term emission allowances		99		82
Deferred revenue options		94		—
Chicago agreement(c)		55		59
Chicago arbitration settlement(d)		52		55
Unamortized debt expense		48		39
Other		107		178
Total other deferred debits and other assets	$	824	$	1,418

(a) See Note 8—Intangible Assets for further information.

(b) Long-term prepaid state income taxes relate to ComEd’s overpayment of state income taxes. The overpayment will be applied towards future state income tax payments.

(c) On February 20, 2003, ComEd entered into separate agreements with Chicago and with Midwest Generation. Under the terms of the agreement with Chicago, ComEd will pay Chicago and other parties a total of $60 million over ten years and be relieved of a requirement, originally transferred to Midwest Generation upon the sale of ComEd’s fossil stations in 1999, to build a 500-MW generation facility. These payments were deferred and are amortized ratably over the life of the franchise agreement with Chicago through 2020.

(d) On March 22, 1999, ComEd reached a settlement agreement with Chicago to end the arbitration proceeding between ComEd and Chicago regarding the January 1, 1992 franchise agreement and a supplement agreement. As part of the settlement agreement, ComEd paid $25 million each year from 1999 to 2002 to help ensure an adequate and reliable electric supply for Chicago. These payments were deferred and are amortized ratably over the life of the franchise agreement with Chicago through 2020.

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

The following table provides additional information about liabilities recorded within Exelon’s Consolidated Balance Sheets as of December 31, 2005 and 2004.

	December 31,
	2005		2004
Accrued expenses
Compensation-related accruals(a)	$	377	$	346
Taxes accrued		256		312
Interest accrued		258		252
Severance accrued		20		69
Other accrued expenses		94		118
Total accrued expenses	$	1,005	$	1,097

(a) Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.

The following table provides information regarding counterparty margin deposit accounts as of December 31, 2005 and 2004.

	December 31,
	2005		2004
Other current assets
Counterparty collateral deposits paid	$	285	$	41
Other current liabilities
Counterparty collateral deposits received		101		44

The following table provides additional information about accumulated other comprehensive income recorded (after tax) within Exelon’s Consolidated Balance Sheets as of December 31, 2005 and 2004.

	December 31,
	2005			2004
Accumulated other comprehensive loss
Minimum pension liability	$	(1,362	)	$	(1,372	)
Net unrealized loss on cash-flow hedges		(337	)		(138	)
Unrealized gain on marketable securities		75			61
Foreign currency translation adjustment		—			3
Total accumulated other comprehensive loss	$	(1,624	)	$	(1,446	)

256

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

The following tables provide information about the regulatory assets and liabilities of ComEd and PECO as of December 31, 2005 and 2004.

	December 31,
ComEd	2005			2004
Regulatory assets (liabilities)
Nuclear decommissioning	$	(1,435	)	$	(1,433	)
Removal costs		(1,015	)		(1,011	)
Reacquired debt costs and interest-rate swap settlements		107			118
Conditional asset retirement obligations		91			—
Recoverable transition costs		43			87
Deferred income taxes		8			4
Other		31			31
Total regulatory assets (liabilities)	$	(2,170	)	$	(2,204	)

	December 31,
PECO	2005			2004
Regulatory assets (liabilities)
Competitive transition charges	$	3,532		$	3,936
Deferred income taxes		781			747
Non-pension postretirement benefits		45			52
Reacquired debt costs		36			42
MGP regulatory asset		26			32
DOE facility decommissioning		13			19
Conditional asset retirement obligations		13			—
Nuclear decommissioning		(68	)		(46	)
Other		8			8
Long-term regulatory assets		4,386			4,790
Deferred energy costs (current asset)		39			25
Total regulatory assets (liabilities)	$	4,425		$	4,815

Nuclear decommissioning.These amounts represent future nuclear decommissioning costs that exceed (regulatory asset) or are less than (regulatory liability) the associated decommissioning trust fund assets. Exelon believes the trust fund assets, including prospective earnings thereon and any future collections from customers, will equal the associated future decommissioning costs at the time of decommissioning. See Note 13—Nuclear Decommissioning and Spent Fuel Storage for further information.

Removal costs. These amounts represent funds received from customers to cover the future removal of property, plant and equipment. See Note 6—Property, Plant and Equipment for further information.

Reacquired debt costs and interest-rate swap settlements. The reacquired debt 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. Interest-rate swap settlements are deferred and amortized over the period that the related debt is outstanding.

257

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Conditional asset retirement obligations.These costs represent future removal costs associated with retirement obligations which will be collected over the remaining lives of the underlying assets. See Note 14—Conditional ARO for further information.

Recoverable transition costs. These charges, related to amounts that would have been unrecoverable but for the recovery mechanism, such as the CTC allowed under the Illinois restructuring act, 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. See Note 4—Regulatory Issues for discussion of recoverable transition cost amortization.

Deferred income taxes. These costs represent the difference between the method by which the regulator allows for the recovery of income taxes and how income taxes would be recorded by unregulated entities. 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 rate-making policies of the ICC and PAPUC, as well as the revenue impacts thereon, and assume continued recovery of these costs in future rates. See Note 12—Income Taxes for further information.

Competitive transition charges. These charges represent PECO’s stranded costs that the PAPUC determined would 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, an unconsolidated subsidiary of PECO, in connection with the securitization of PECO’s stranded cost recovery. These charges are being amortized through December 31, 2010 with a return on the unamortized balance of 10.75%.

Non-pension postretirement benefits. These costs are the result of transitioning to SFAS No. 106 in 1993, which are recoverable in rates through 2012.

MGP regulatory asset. These costs represent estimated MGP-related environmental remediation costs at PECO which are recoverable through regulated gas rates.

DOE facility decommissioning. These costs represent PECO’s share of recoverable decommissioning and decontamination costs of the DOE nuclear fuel enrichment facilities established by the National Energy Policy Act of 1992.

Deferred energy costs (current asset). These costs represent fuel costs recoverable under the purchase gas adjustment clause.

Recovery of regulatory assets.The regulatory assets related to deferred income taxes and non-pension post retirement benefits did not require a cash outlay of investor supplied funds; consequently, these costs are not earning a rate of return. Recovery of the regulatory assets for conditional asset retirement obligations, reacquired debt costs, recoverable transition costs, MGP remediation costs, DOE facility decommissioning and deferred energy costs is provided for through regulated revenue sources. Therefore, these costs are earning a rate of return.

22. Segment Information

Exelon has three operating segments: ComEd, PECO and Generation. Exelon evaluates the performance of its business segments based on net income. As a result of developments during the

258

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

fourth quarter of 2005, Exelon has concluded that it can no longer aggregate ComEd and PECO as a single reportable segment. These developments include the approaching end of the regulatory transition period and rate freeze in Illinois, the opposition to rate increases expressed by the Attorney General of the State of Illinois, changes in the ComEd Board of Directors and the selection of executive officers of ComEd with no responsibilities outside of ComEd. As a result, ComEd and PECO are no longer reported as a combined Energy Delivery reportable segment. For more information regarding ComEd’s regulatory issues, see ComEd—Retail Electric Services below and Note 4 of Exelon’s Notes to the Consolidated Financial Statements. Additionally, Exelon sold or wound down substantially all components of Exelon Enterprises Company, LLC (Enterprises) in 2004 and 2003. As such, Exelon ceased reporting Enterprises as a segment as of January 1, 2005. Prior period presentation has been adjusted for comparative purposes.

ComEd’s business consists of the purchase and regulated retail and wholesale sale of electricity and distribution and transmission services in northern Illinois, including the City of Chicago. PECO’s business consists of the purchase and regulated retail sale of electricity and distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and distribution services in the Pennsylvania counties surrounding the City of Philadelphia. Generation consists principally of the electric generating facilities and wholesale energy marketing operations of Generation, the competitive retail sales business of Exelon Energy Company, Generation’s interest in Sithe and certain other generation projects.

See Note 3—Acquisitions and Dispositions for information regarding dispositions within the Generation segment and Enterprises in 2005, 2004 and 2003. Also, see Note 2—Discontinued Operations for information regarding Exelon’s discontinued operations.

Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, was transferred to Generation. Segment information for 2003 included in the table below has been adjusted to reflect Exelon Energy Company as part of the Generation segment.

259

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

An analysis and reconciliation of Exelon’s business segment information to the respective information in the consolidated financial statements are as follows:

	ComEd			PECO			Generation (a)			Other (b)			Intersegment Eliminations			Consolidated
Total revenues(c):
2005	$	6,264		$	4,910		$	9,046		$	694		$	(5,557	)	$	15,357
2004		5,803			4,487			7,703			670			(4,530	)		14,133
2003		5,814			4,388			8,586			792			(4,432	)		15,148
Intersegment revenues:
2005	$	8		$	8		$	4,848		$	693		$	(5,557	)	$	—
2004		18			9			3,841			669			(4,537	)		—
2003		65			11			3,920			479			(4,475	)		—
Depreciation and amortization:
2005	$	413		$	566		$	254		$	101		$	—		$	1,334
2004		410			518			286			81			—			1,295
2003		386			487			200			42			—			1,115
Operating expenses(c):
2005	$	6,276		$	3,861		$	7,194		$	859		$	(5,557	)	$	12,633
2004		4,186			3,473			6,664			842			(4,531	)		10,634
2003		4,247			3,332			8,689			904			(4,433	)		12,739
Interest expense:
2005	$	295		$	280		$	128		$	131		$	(5	)	$	829
2004		369			303			103			61			(8	)		828
2003		423			324			88			47			(9	)		873
Income taxes:
2005	$	363		$	247		$	709		$	(375	)	$	—		$	944
2004		457			249			401			(394	)		—			713
2003		465			253			(176	)		(153	)		—			389
Income (loss) from continuing operations
2005	$	(676	)	$	520		$	1,109		$	(2	)	$	—		$	951
2004		676			455			657			82			—			1,870
2003		702			473			(238	)		(45	)		—			892
Income (loss) from discontinued operations
2005	$	—		$	—		$	19		$	(5	)	$	—		$	14
2004		—			—			(16	)		(13	)		—			(29	)
2003		—			—			(21	)		(78	)		—			(99	)
Cumulative effect of changes in accounting principles:
2005	$	(9	)	$	(3	)	$	(30	)	$	—		$	—		$	(42	)
2004		—			—			32			(9	)		—			23
2003		5			—			108			(1	)		—			112
Net income (loss):
2005	$	(685	)	$	517		$	1,098		$	(7	)	$	—		$	923
2004		676			455			673			60			—			1,864
2003		707			473			(151	)		(124	)		—			905
Capital expenditures:
2005	$	776		$	298		$	1,067		$	24		$	—		$	2,165
2004		721			225			960			15			—			1,921
2003		712			250			953			39			—			1,954
Total assets:
2005	$	17,211		$	10,018		$	17,724		$	(2,564	)	$	—		$	42,389
2004		17,441			10,087			16,438			(1,242	)		—			42,724
2003		17,965			10,373			14,649			(1,088	)		—			41,899

260

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

(a) Effective January 1, 2004, Enterprises’ competitive retail sales business, Exelon Energy Company, was transferred to Generation. Segment information for 2003 included in the table above has been adjusted to reflect Exelon Energy Company as part of the Generation segment.

(b) Other includes corporate operations, shared service entities, including BSC, Enterprises and investments in synthetic fuel-producing facilities.

(c) Utility taxes of $247 million, $234 million and $233 million are included in revenues and expenses for 2005, 2004 and 2003, respectively, for ComEd. Utility taxes of $230 million, $205 million and $206 million are included in revenues and expenses for 2005, 2004 and 2003, respectively, for PECO.

23. Related Party Transactions

Effective December 31, 2003, ComEd Financing II, ComEd Financing III, ComEd Funding, ComEd Funding Trust, PETT, PECC and PECO Trust III were deconsolidated from the financial statements of Exelon in conjunction with the adoption of FIN 46-R. Effective July 1, 2003, PECO Trust IV was deconsolidated from the financial statements of PECO in conjunction with the adoption of FIN 46. Prior periods were not restated.

Exelon’s financial statements reflect related-party transactions with its unconsolidated affiliates as presented in the tables below.

	For the Years Ended December 31,
	2005			2004			2003
Operating revenues from affiliates
ComEd Transitional Funding Trust	$	3		$	3		$	—
PETT(a)		9			10			—
Interest expense to affiliates
ComEd Transitional Funding Trust		66			85			—
ComEd Financing II		13			13			—
ComEd Financing III		13			13			—
PETT		212			235			—
PECO Trust III		6			6			—
PECO Trust IV		6			6			3
Equity in earnings (losses) of unconsolidated affiliates
ComEd Funding LLC		(14	)		(20	)		—
ComEd Financing III		—			1			—
PETT		(16	)		(25	)		—

(a) PECO receives a monthly service fee from PETT based on a percentage of the outstanding balance of all series of transition bonds.

261

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

	December 31,
	2005		2004
Receivables from affiliates (current)
ComEd Transitional Funding Trust	$	14	$	9
Investment in affiliates
ComEd Transitional Funding LLC		18		36
ComEd Financing II		10		10
ComEd Financing III		6		6
PETT		63		77
PECO Energy Capital Corp		4		4
PECO Trust IV		6		6
Receivable from affiliates (noncurrent)
ComEd Transitional Funding Trust		12		10
Payables to affiliates (current)
ComEd Financing II		6		6
ComEd Financing III		4		4
PECO Trust III		1		1
Long-term debt to ComEd Transitional Funding Trust and other financing trusts (including due within one year)
ComEd Transitional Funding Trust		987		1,341
ComEd Financing II		155		155
ComEd Financing III		206		206
PETT		2,975		3,456
PECO Trust III		81		81
PECO Trust IV		103		103

24. Quarterly Data (Unaudited)

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

	Operating Revenues				Operating Income (Loss)					Income (Loss) Before the Cumulative Effect of Changes In Accounting Principles					Net Income (Loss)
	2005		2004		2005			2004		2005			2004		2005			2004
Quarter ended:
March 31	$	3,561	$	3,635	$	931		$	771	$	521		$	380	$	521		$	412
June 30(a)		3,484		3,438		897			853		514			521		514			521
September 30		4,473		3,748		1,312			1,198		725			577		725			568
December 31(b)		3,838		3,312		(416	)		677		(795	)		363		(837	)		363

(a) During the second quarter of 2004, Enterprises sold its Chicago business of Thermal and recorded a gain of $45 million (before income taxes). The results of Thermal have been classified as discontinued operations within the Consolidated Statements of Income.

(b) Results of operations for the quarter ended December 31, 2005 included a $1.2 billion impairment of ComEd’s goodwill.

262

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

	Average Basic Shares Outstanding (in millions)		Earnings (Losses) per Basic Share Before the Cumulative Effect of Changes in Accounting Principles					Net Income (Loss) per Basic Share
	2005	2004	2005			2004		2005			2004
Quarter ended:
March 31	666	659	$	0.78		$	0.58	$	0.78		$	0.63
June 30	670	661		0.77			0.79		0.77			0.79
September 30	670	661		1.08			0.87		1.08			0.86
December 31 (a)	668	664		(1.19	)		0.55		(1.25	)		0.55

(a) Results of operations for the quarter ended December 31, 2005 included a $1.2 billion impairment of ComEd’s goodwill.

	Average Diluted Shares Outstanding (in millions)		Earnings (Losses) per Diluted Share Before the Cumulative Effect of Changes in Accounting Principles					Net Income (Loss) per Diluted Share
	2005	2004	2005			2004		2005			2004
Quarter ended:
March 31	675	665	$	0.77		$	0.56	$	0.77		$	0.62
June 30	677	667		0.76			0.78		0.76			0.78
September 30	677	669		1.07			0.86		1.07			0.85
December 31(a)	668	672		(1.19	)		0.54		(1.25	)		0.54

(a) Results of operations for the quarter ended December 31, 2005 included a $1.2 billion impairment of ComEd’s goodwill.

The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis:

	2005								2004
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter		Fourth Quarter		Third Quarter		Second Quarter		First Quarter
High price	$	56.00	$	57.46	$	52.01	$	47.18	$	44.90	$	37.90	$	34.89	$	34.43
Low price		46.62		49.60		44.14		41.77		36.73		32.69		30.92		32.18
Close		53.14		53.44		51.33		45.89		44.07		36.69		33.29		34.43
Dividends		0.400		0.400		0.400		0.400		0.400		0.305		0.275		0.275

25. Subsequent Events

PECO’s Capital Stock Tax and Franchise Tax (CS/FT). On February 1, 2006, PECO was notified that the Pennsylvania (PA) Board of Finance and Revenue (BF&R) approved, in a 6-0 decision, PECO’s request for resettlement of its 2001 and 2002 CS/FT liability. Based on this approval, Exelon reduced liabilities associated with its previously estimated CS/FT liabilities for the years 2001 through 2004 by a total of $11 million (after-tax), which has been reflected in Exelon’s Consolidated Statements of Income for the year ended December 31, 2005 and Consolidated Balance Sheets as of December 31, 2005.

263

Exelon Corporation and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

The basis for computing the CS/FT includes a five-year rolling average of the legal entity’s net income. PECO had appealed to the PA Department of Revenue regarding the inclusion of certain income included in the calculation of these taxes.

Nuclear Generating Station Groundwater. On December 16, 2005, the Illinois Environmental Protection Agency (Illinois EPA) issued a Violation Notice to Generation alleging that the company had violated state groundwater standards as a result of historical discharges of liquid tritium from a line at the Braidwood Nuclear Generating Station. In November 2005, Generation discovered that spills from the line in 1998 and 2000 have resulted in a tritium plume in groundwater that is both on and off the plant site. Levels of tritium in portions of the plume are in excess of the Illinois EPA groundwater standard. Levels in portions of the plume also exceed the Illinois EPA and Federal limits for drinking water. However, samples from drinking water wells on property adjacent to the plant have shown that, with one exception, tritium levels in these wells are below levels that naturally occur. The tritium level in one drinking water well is elevated above levels that naturally occur, but is significantly below the state and federal drinking water standards, and Generation believes that this level poses no threat to human health. Generation has suspended liquid tritium discharges into the affected pipeline, and is investigating the causes of the releases to ensure that necessary corrective actions are taken to prevent another occurrence. Generation has analyzed the various remediation options for the groundwater, and submitted an initial report to the Illinois EPA on February 2, 2006. The Illinois EPA will determine the required remediation and whether a civil penalty will be assessed against Generation. Generation has notified 14 potentially affected adjacent property owners that, upon sale of their property, it will reimburse them for any diminution in property value caused by the release, and has purchased the property of one adjacent owner. As of December 31, 2005, Exelon recorded a reserve of $7 million (pre-tax) for this matter, which Exelon deems adequate to cover the costs of remediation and potential related corrective measures.

Also, as a result of intensified monitoring and inspection efforts in 2006, Exelon detected a small underground tritium leak at the Dresden Generating Station and tritium concentrations in standing water within concrete vaults at the Byron Generating Station. Neither of these discharges occurred outside the property lines of the plant, nor does Exelon believe either of these matters poses health or safety threats to employees or to the public. In response to the detection of tritium in water samples taken at the aforementioned nuclear generating stations, Exelon has launched an initiative across its ten-station nuclear fleet to systematically assess systems that handle tritium and take the necessary actions to minimize the risk of inadvertent discharge of tritium to the environment. The assessments will take place in 2006 and will cover pipes, pumps, valves, tanks and other pieces of equipment that carry tritiated water in and around the plants. At this time, Exelon cannot estimate the costs that may be incurred in connection with tritium assessment initiatives or possible remediation efforts of the Dresden and Byron matters.

Generation Credit Facilities Agreement. On February 10 through 13, 2006, Generation entered into separate additional credit facilities with aggregate bank commitments of $875 million, which may be drawn down in the form of loans and/or letters of credit. The additional credit facilities are each for a term of 364 days and contain the same terms as the revolving credit facilities described in Note 10—Notes Payable and Short-Term Debt. The credit facilities will be used primarily to meet short-term funding requirements and to issue letters of credit.

264

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

ComEd

Executive Overview

A discussion of items pertinent to ComEd’s executive overview is set forth under “EXELON CORPORATION—Executive Overview” of this Report.

Results of Operations

Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

A discussion of ComEd’s results of operations for 2005 compared 2004 is set forth under “Results of Operations—ComEd” in “EXELON CORPORATION—Results of Operations” of this Report.

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

A discussion of ComEd’s results of operations for 2004 compared to 2003 is set forth under “Results of Operations—ComEd” in “EXELON CORPORATION—Results of Operations” of this Report.

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 the capital markets at reasonable terms, ComEd has access to a revolving credit facility that ComEd currently utilizes to support its commercial paper program. See the “Credit Matters” section of “Liquidity and Capital Resources” for further discussion.

Capital resources are used primarily to fund ComEd’s capital requirements, including construction, retirement of debt, the payment of dividends and contributions to Exelon’s pension plans.

Cash Flows from Operating Activities

A discussion of items pertinent to ComEd’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

Cash Flows from Investing Activities

A discussion of items pertinent to ComEd’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

Cash Flows from Financing Activities

A discussion of items pertinent to ComEd’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

265

Credit Matters

A discussion of credit matters pertinent to ComEd is set forth under “Credit Matters” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report

Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations

A discussion of ComEd’s contractual obligations, commercial commitments and off-balance sheet obligations is set forth under “Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

Critical Accounting Policies and Estimates

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

New Accounting Pronouncements

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK—ComEd

ComEd is exposed to market risks associated with commodity price, credit and interest rates. These risks are described above under “Quantitative and Qualitative Disclosures about Mark Risk— Exelon.”

266

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ComEd

Report of Independent Registered Public Accounting Firm

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 its subsidiaries (ComEd) at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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 the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 asset retirement obligations as of January 1, 2003; its method of accounting for variable interest entities in 2003; and its method of accounting for conditional asset retirement obligations as of December 31, 2005.

PricewaterhouseCoopers LLP

Chicago, Illinois

February 15, 2006

267

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Income

	For the Years Ended December 31,
(in millions)	2005			2004			2003
Operating revenues
Operating revenues	$	6,253		$	5,782		$	5,749
Operating revenues from affiliates		11			21			65
Total operating revenues		6,264			5,803			5,814
Operating expenses
Purchased power		346			214			22
Purchased power from affiliate		3,174			2,374			2,479
Operating and maintenance		640			705			970
Operating and maintenance from affiliates		193			192			123
Impairment of goodwill		1,207			—			—
Depreciation and amortization		413			410			386
Taxes other than income		303			291			267
Total operating expenses		6,276			4,186			4,247
Operating income (loss)		(12	)		1,617			1,567
Other income and deductions
Interest expense		(203	)		(258	)		(423	)
Interest expense to affiliates		(92	)		(111	)		—
Distributions on mandatorily redeemable preferred securities		—			—			(26	)
Equity in losses of unconsolidated affiliates		(14	)		(19	)		—
Interest income from affiliates		4			20			25
Net loss on extinguishment of long-term debt		—			(130	)		—
Other, net		4			14			24
Total other income and deductions		(301	)		(484	)		(400	)
Income (loss) before income taxes and cumulative effect of a change in accounting principle		(313	)		1,133			1,167
Income taxes		363			457			465
Income (loss) before cumulative effect of a change in accounting principle		(676	)		676			702
Cumulative effect of a change in accounting principle (net of income taxes of $(6) and $0)		(9	)		—			5
Net income (loss)	$	(685	)	$	676		$	707

See Notes to Consolidated Financial Statements

268

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Cash Flows

	For the Years Ended December 31,
(in millions)	2005			2004			2003
Cash flows from operating activities
Net income (loss)	$	(685	)	$	676		$	707
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Depreciation and amortization		413			410			386
Cumulative effect of a change in accounting principle (net of income taxes)		9			—			(5	)
Deferred income taxes and amortization of investment tax credits		226			153			7
Provision for uncollectible accounts		24			37			46
Equity in losses of unconsolidated affiliates		14			19			—
Impairment of goodwill		1,207			—			—
Other non-cash operating activities		39			95			61
Changes in assets and liabilities:
Accounts receivable		(108	)		(82	)		62
Inventories		(1	)		(4	)		14
Other current assets		(10	)		7			(18	)
Accounts payable, accrued expenses and other current liabilities		45			61			34
Change in receivables and payables to affiliates		28			30			(155	)
Income taxes		(137	)		109			(107	)
Pension and non-pension postretirement benefits obligation		(802	)		(147	)		(48	)
Other noncurrent assets and liabilities		(15	)		(34	)		(36	)
Net cash flows provided by operating activities		247			1,330			948
Cash flows from investing activities
Capital expenditures		(776	)		(721	)		(712	)
Changes in Exelon intercompany money pool contributions		308			97			(405	)
Receipt of notes receivable from affiliates		—			1,071			213
Change in restricted cash		—			20			(15	)
Settlement of interest-rate swaps		(15	)		—			—
Other investing activities		4			19			26
Net cash flows provided by (used in) investing activities		(479	)		486			(893	)
Cash flows from financing activities
Issuance of long-term debt		91			—			1,497
Retirement of long-term debt		(417	)		(1,231	)		(1,425	)
Retirement of long-term debt to ComEd Transitional Funding Trust		(354	)		(335	)		—
Change in Exelon intercompany money pool borrowings		140			—			—
Issuance of mandatorily redeemable preferred securities		—			—			200
Retirement of mandatorily redeemable preferred securities		—			—			(200	)
Retirement of preferred stock		(9	)		—			—
Change in short-term debt		459			—			(71	)
Dividends paid on common stock		(498	)		(457	)		(401	)
Contributions from parent		834			175			451
Settlement of cash-flow and fair-value hedges		—			26			(45	)
Other financing activities		(6	)		2			(43	)
Net cash flow provided by (used in) financing activities		240			(1,820	)		(37	)
Increase (decrease) in cash and cash equivalents		8			(4	)		18
Cash and cash equivalents at beginning of period		30			34			16
Cash and cash equivalents at end of period	$	38		$	30		$	34

See Notes to Consolidated Financial Statements

269

Commonwealth Edison Company and Subsidiary Companies

Consolidated Balance Sheets

	December 31,
(in millions)	2005			2004
Assets
Current assets
Cash and cash equivalents	$	38		$	30
Accounts receivable, net
Customer		806			726
Other		46			50
Inventories, at average cost		50			48
Deferred income taxes		13			—
Receivables from affiliates		37			10
Contributions to Exelon intercompany money pool		—			308
Other		34			24
Total current assets		1,024			1,196
Property, plant and equipment, net		9,906			9,463
Deferred debits and other assets
Investments		41			39
Investments in affiliates		34			52
Goodwill		3,475			4,705
Receivables from affiliates		1,447			1,443
Prepaid pension asset		938			156
Other		346			387
Total deferred debits and other assets		6,281			6,782
Total assets	$	17,211		$	17,441
Liabilities and shareholders’ equity
Current liabilities
Long-term debt due within one year	$	328			272
Long-term debt to ComEd Transitional Funding Trust due within one year		307			321
Accounts payable		223			196
Accrued expenses		417			589
Payables to affiliates		278			227
Notes payable		459			—
Borrowings from Exelon intercompany money pool		140			—
Customer deposits		110			93
Deferred income taxes		—			17
Other		46			49
Total current liabilities		2,308			1,764
Long-term debt		2,500			2,901
Long-term debt to ComEd Transitional Funding Trust		680			1,020
Long-term debt to other financing trusts		361			361
Deferred credits and other liabilities
Deferred income taxes		2,147			1,890
Unamortized investment tax credits		43			45
Asset retirement obligations		151			1
Non-pension postretirement benefits obligation		175			195
Payables to affiliates		—			17
Regulatory liabilities		2,170			2,204
Other		280			303
Total deferred credits and other liabilities		4,966			4,655
Total liabilities		10,815			10,701
Commitments and contingencies
Shareholders’ equity
Common stock		1,588			1,588
Preference stock		—			7
Other paid in capital		4,890			4,168
Receivable from parent		—			(125	)
Retained earnings (deficit)		(81	)		1,102
Accumulated other comprehensive income (loss)		(1	)		—
Total shareholders’ equity		6,396			6,740
Total liabilities and shareholders’ equity	$	17,211		$	17,441

See Notes to Consolidated Financial Statements

270

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)			Total Shareholders’ Equity
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
Net income		—		—			—			—			676			—			—			676
Repayment of receivable from parent		—		—			—			125			—			—			—			125
Allocation of tax benefit from parent		—		—			55			—			—			—			—			55
Appropriation of retained earnings for future dividends		—		—			—			—			(676	)		676			—			—
Common stock dividends		—		—			—			—			(174	)		(283	)		—			(457	)
Merger fair value adjustments		—		—			(2	)		—			—			—			—			(2	)
Other comprehensive income, net of income taxes of $2		—		—			—			—			—			—			1			1
Balance, December 31, 2004		1,588		7			4,168			(125	)		—			1,102			—			6,740
Net loss		—		—			—			—			(685	)		—			—			(685	)
Repayment of receivable from parent		—		—			—			125			—			—			—			125
Capital contribution from parent		—		—			709			—			—			—			—			709
Allocation of tax benefit from parent		—		—			27			—			—			—			—			27
Appropriation of retained earnings for future dividends		—		—			—			—			(495	)		495			—			—
Common stock dividends		—		—			—			—			—			(498	)		—			(498	)
Merger fair value adjustments		—		—			(14	)		—			—			—			—			(14	)
Redemption of preferred stock		—		(7	)		—			—			—			—			—			(7	)
Other comprehensive loss, net of income taxes of $(1)		—		—			—			—			—			—			(1	)		(1	)
Balance, December 31, 2005	$	1,588	$	—		$	4,890		$	—		$	(1,180	)	$	1,099		$	(1	)	$	6,396

See Notes to Consolidated Financial Statements

271

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Comprehensive Income

	For the Years Ended December 31,
(in millions)	2005			2004		2003
Net income	$	(685	)	$	676	$	707
Other comprehensive income (loss)
Change in net unrealized gain on cash-flow hedges, net of income taxes of $0, $0 and $21, respectively		—			—		31
Foreign currency translation adjustment, net of income taxes of $(1), $1 and $0, respectively		(2	)		—		3
Unrealized gain on marketable securities, net of income taxes of $0, $1 and $2, respectively		1			1		3
Total other comprehensive income (loss)		(1	)		1		37
Total comprehensive income (loss)	$	(686	)	$	677	$	744

See Notes to Consolidated Financial Statements

272

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements

(Dollars in millions unless otherwise noted)

1. Significant Accounting Policies

Description of Business

Commonwealth Edison Company (ComEd) is a regulated utility 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 (Chicago), an area of about 225 square miles with an estimated population of three million. ComEd has approximately 3.7 million customers.

Basis of Presentation

ComEd, a regulated electric utility, is a principal subsidiary of Exelon Corporation (Exelon), which owns 99.9% of ComEd’s common stock.

ComEd’s consolidated financial statements include the accounts of ComEd and Commonwealth Edison Company of Indiana, Inc. Edison Development Canada Inc. (EDCAN) and Edison Finance Partnership (EFP) were consolidated prior to their accounting liquidation in 2005 pending legal dissolution which is expected in 2006. Commonwealth Research Corporation and Edison Development Company were consolidated prior to their dissolution in 2004. All intercompany transactions have been eliminated.

Certain trusts and limited partnerships that are financing subsidiaries of ComEd have issued debt or mandatorily redeemable preferred securities. In accordance with FASB Interpretation No. (FIN) 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN 46-R), 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 as of December 31, 2003. ComEd Funding and ComEd Funding Trust are separate legal entities from ComEd; the debt issued by these subsidiaries is solely their obligation, and their assets, including transitional property, are not available to creditors of ComEd. See “Variable Interest Entities” below for further discussion of the adoption of FIN 46-R and the deconsolidation of these financing subsidiaries.

Reclassifications

Certain prior year amounts have been reclassified in the financial statements for comparative purposes. The reclassifications did not affect net income.

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, asset retirement obligations, inventory reserves, allowance for doubtful accounts, goodwill and asset impairments, pension and other postretirement benefits, derivative instruments, fixed asset depreciation, environmental costs, taxes, severance and unbilled energy revenues.

273

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 accounts for its operations in accordance with accounting policies prescribed by the regulatory authorities having jurisdiction, principally the Illinois Commerce Commission (ICC) under state public utility laws, the Federal Energy Regulatory Commission (FERC) under various Federal laws and the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA) prior to its repeal effective February 8, 2006. ComEd applies SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” (SFAS No. 71). SFAS No. 71 requires ComEd to record in its financial statements the effects of rate regulation 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 its currently recorded regulatory assets and liabilities will be recovered in future rates. However, ComEd continues to evaluate its ability to apply SFAS No. 71, including the current events related to the regulatory and political environment in Illinois. If a separable portion of ComEd’s business were no longer to meet the provisions of SFAS No. 71, ComEd would be required to eliminate from its financial statements the effects of regulation, which could have a material impact on its financial condition and results of operations. See Note 3—Regulatory Issues for further information regarding the repeal of PUCHA effective February 8, 2006.

Segment Information

ComEd operates in one business segment.

Variable Interest Entities

FIN 46 and its revision FIN 46-R addressed the requirements for consolidating certain variable interest entities. FIN 46 was effective for variable interest entities created after January 31, 2003. FIN 46-R was effective December 31, 2003 for variable interest entities that were considered to be special-purpose entities and as of March 31, 2004 for all other variable interest entities.

Pursuant to the provisions of FIN 46-R, as of December 31, 2003, the financing trusts of ComEd, namely ComEd Financing II (formed in November 1996), ComEd Financing III (formed in September 2002), ComEd Funding LLC (formed in July 1998) and ComEd Transitional Funding Trust (formed in October 1998), were deconsolidated from ComEd’s financial statements. Amounts owed to these financing trusts at December 31, 2005 and 2004 of $1.3 billion and $1.7 billion, respectively, were recorded as debt to financing trusts within ComEd’s Consolidated Balance Sheets.

This change in presentation related to the financing trusts had no effect on ComEd’s net income. In accordance with FIN 46-R, prior periods were not restated. The maximum exposure to loss as a result of ComEd’s involvement with the financing trusts was $46 million and $62 million at December 31, 2005 and 2004, respectively.

Revenues

Operating revenues are recorded as service is rendered or electricity is delivered to customers. At the end of each month, ComEd accrues an estimate for the unbilled amount of electricity delivered or services provided to customers (see Note 4—Accounts Receivable).

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 benefits carried forward.

274

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Investment tax credits previously utilized 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.

Pursuant to the Internal Revenue Code, Exelon and its subsidiaries file a consolidated Federal income tax return that includes its subsidiaries in which it owns at least 80% of the outstanding stock. Income taxes are allocated to each of Exelon’s subsidiaries included in the filing of the consolidated Federal income tax return based on the separate return method. ComEd records an income tax valuation allowance for deferred tax assets which are not more likely than not to be realized in the future (see Note 10—Income Taxes).

ComEd is a party to an agreement (Tax Sharing Agreement) with Exelon and other subsidiaries of Exelon 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.

Losses on Reacquired Debt

Recoverable 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 rate-making purposes. Losses on other reacquired debt are recognized in ComEd’s Consolidated Statements of Income as incurred.

Comprehensive Income

Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to shareholders. Other comprehensive income primarily relates to unrealized gains and losses on cash-flow hedge instruments. Comprehensive income is reflected in ComEd’s Consolidated Statements of Changes in Shareholders’ Equity and ComEd’s 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.

Allowance for Doubtful Accounts

The allowance for doubtful accounts reflects ComEd’s best estimate of probable losses in the accounts receivable balance. The allowance is based on known troubled accounts, historical experience and other currently available evidence. Customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, typically monthly. Customer accounts are written off based upon approved regulatory requirements.

Inventories

Inventory is recorded at the lower of cost or market, and provisions are made for excess and obsolete inventory. Materials and supplies inventory generally includes the average costs of

275

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

transmission and distribution materials. Materials are generally charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

Marketable Securities

Marketable securities are classified as available-for-sale securities and are reported at fair value pursuant to SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS No. 115) with the unrealized gains and losses, net of tax, reported in other comprehensive income. At December 31, 2005 and 2004, ComEd had no held-to-maturity securities.

Leases

ComEd accounts for leases in accordance with SFAS No. 13, “Accounting for Leases” and determines whether its long-term purchase power and sales contracts are leases pursuant to EITF Issue No. 01-8, “Determining Whether an Arrangement is a Lease” (EITF 01-8). At the inception of the lease, or subsequent modification, ComEd determines whether the lease is an operating or capital lease based upon its terms and characteristics.

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.

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 composite method of depreciation. For unregulated property, the cost and accumulated depreciation of property, plant and equipment retired or otherwise disposed of are removed from the related accounts.

See Note 5—Property, Plant and Equipment and Note 18—Supplemental Financial Information for additional information regarding 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, 2005 and 2004, net unamortized capitalized software costs totaled $122 million and $139 million, respectively. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed ten years. Certain capitalized software costs are being amortized over fifteen years pursuant to regulatory approval. During 2005, 2004 and 2003, ComEd amortized capitalized software costs of $22 million, $34 million and $33 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 using the composite method. Annual depreciation provisions for financial reporting purposes,

276

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

presented by average service life and as a percentage of average service life for each asset category, are presented in the tables below. See Note 5—Property, Plant and Equipment for information regarding a change in ComEd’s depreciation rates.

Average Service Life in Years by Asset Category	2005	2004	2003
Electric—transmission and distribution	25-75	25-75	25-75
Other property and equipment	5-58	5-58	5-58
Average Service Life Percentage by Asset Category	2005	2004	2003
Electric—transmission and distribution	3.12%	3.16%	3.20%
Other property and equipment	5.57%	5.77%	7.14%

Amortization of regulatory assets is provided over the recovery period specified in the related legislation or regulatory agreement. See Note 18—Supplemental Financial Information for further information regarding ComEd’s regulatory assets.

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 is recorded as a charge to construction work in progress and as a non-cash credit to AFUDC that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities (see Note 18—Supplemental Financial Information). ComEd recorded credits to AFUDC of $7 million, $3 million and $15 million in 2005, 2004 and 2003, respectively.

Asset Impairments

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. Pursuant to SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142), goodwill is not 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. See Note 6—Goodwill for information regarding the adoption of SFAS No. 142 and the results of goodwill impairment studies that have been performed, which include the $1.2 billion goodwill impairment charge recorded in 2005.

Derivative Financial Instruments

ComEd enters into derivatives to manage its exposure to fluctuations in interest rates, changes in interest rates related to planned future debt issuances and changes in the fair value of outstanding debt. ComEd’s derivative activities are in accordance with Exelon’s Risk Management Policy (RMP).

ComEd 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 or normal sales exception. Derivatives on the balance sheet are presented as current or noncurrent mark-to-market derivative assets or liabilities. Changes in the fair value of derivatives are recognized in earnings unless specific hedge accounting criteria are met, in which case those changes

277

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

are recorded in earnings as an offset to the changes in fair value of the exposure being hedged or deferred in accumulated other comprehensive income and recognized in earnings as hedged transactions occur. Amounts recorded in earnings are included in other, net within ComEd’s Consolidated Statements of 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, and is designated and qualifies as, a fair-value hedge, are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. Changes in the fair value of a derivative that is highly effective, and is designated and qualifies as, a cash-flow hedge are deferred in accumulated other comprehensive income and are recognized in earnings as the hedged transactions occur. Any ineffectiveness is recognized in earnings immediately. On an ongoing basis, ComEd assesses the hedge effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that the derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively.

Severance Benefits

ComEd participates in Exelon’s ongoing severance plans, which are accounted for 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.” Amounts associated with severance benefits that are considered probable and can be reasonably estimated are accrued. See Note 7—Severance Accounting for further discussion of ComEd’s accounting for severance benefits.

Retirement Benefits

ComEd participates in Exelon’s defined benefit pension plans and postretirement welfare benefit plans. Exelon’s defined benefit pension plans and postretirement welfare benefit plans are accounted for in accordance with SFAS No. 87, “Employer’s Accounting for Pensions” (SFAS No. 87), SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” (SFAS No. 106) and FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2), and are disclosed in accordance with SFAS No. 132-R, “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an Amendment of FASB Statements No. 87, 88, and 106” (revised 2003) (SFAS No. 132-R). See Note 13—Retirement Benefits for further discussion of ComEd’s accounting for retirement benefits.

FSP FAS 106-2.Through Exelon’s postretirement benefit plans, ComEd provides retirees with prescription drug coverage. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Prescription Drug Act) was enacted on December 8, 2003. 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. Management believes the prescription drug benefit provided under Exelon’s

278

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

postretirement benefit plans is at least actuarially equivalent to the Medicare prescription drug benefit. In response to the enactment of the Prescription Drug Act, in May 2004, the FASB issued FSP FAS 106-2, which provided transition guidance for accounting for the effects of the Prescription Drug Act and superseded FSP FAS 106-1, which had been issued in January 2004. FSP FAS 106-1 permitted 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. ComEd made the one-time election allowed by FSP FAS 106-1 during the first quarter of 2004. During the second quarter of 2004, ComEd early adopted the provisions of FSP FAS 106-2, resulting in a reduction in net periodic post retirement benefit cost.

Foreign Currency Translation

Prior to their accounting liquidation in 2005, pending legal dissolution which is expected in 2006, the financial statements of ComEd’s foreign subsidiaries were prepared in their respective local currencies and translated into U.S. dollars based on the current exchange rates at the end of the periods for ComEd’s Consolidated Balance Sheets and on weighted-average rates for the periods for ComEd’s Consolidated Statements of Income. Foreign currency translation adjustments, net of deferred income tax benefits, are reflected as a component of other comprehensive income on ComEd’s Consolidated Statements of Comprehensive Income and, accordingly, have no effect on net income.

New Accounting Pronouncements

SFAS No. 151. In November 2004, the FASB issued FASB Statement No. 151, “Inventory Costs—an amendment of ARB No. 43, Chapter 4” (SFAS No. 151), which is the result of its efforts to converge U.S. accounting standards for inventories with International Accounting Standards. SFAS No. 151 requires abnormal amounts of idle facility expense, freight, handling costs and wasted material or spoilage to be recognized as current-period charges. It also requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS No. 151 will be effective for inventory costs incurred beginning January 1, 2006. The adoption of this standard is not expected to have a material impact on ComEd.

SFAS No. 123-R.In December 2004, the FASB issued FASB Statement No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123-R). SFAS No. 123-R replaces SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123) and supersedes Accounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees” (APB No. 25). SFAS No. 123-R requires that the compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. Exelon will no longer be permitted to follow the intrinsic value accounting method of APB No. 25. APB No. 25 resulted in no expense being recorded for stock option grants for which the strike price was equal to the fair value of the underlying stock on the date of grant, which has been the situation for Exelon for all years prior to 2006. SFAS No. 123-R will be effective for Exelon in the first quarter of 2006 and will apply to all of Exelon’s outstanding unvested share-based payment awards as of January 1, 2006 and all prospective awards using the modified prospective transition method without restatement of prior periods. Exelon will charge a portion of the resulting expense to ComEd.

In March 2005, the SEC issued Staff Accounting Bulletin (SAB) No. 107 which expressed the views of the SEC regarding the interaction between SFAS No. 123-R and certain SEC rules and

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Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

regulations. SAB No. 107 provides guidance related to the valuation of share-based payment arrangements for public companies, including assumptions such as expected volatility and expected term. See Note 1—Significant Accounting Policies of Exelon’s Notes to Consolidated Financial Statements for further information regarding the estimated impact of Exelon’s adoption of SFAS 123-R.

ComEd participates in Exelon’s stock-based compensation plans. Exelon currently accounts for its stock-based compensation plans under the intrinsic method prescribed by APB No. 25 and related interpretations and follows the disclosure requirements of SFAS No. 123, and SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123.” Accordingly, compensation expense related to stock options recognized within the Consolidated Statements of Income was insignificant in 2005, 2004 and 2003. The table below shows the effect on ComEd’s net income for 2005, 2004 and 2003 had Exelon elected to account for its stock-based compensation plans using the fair-value method under SFAS No. 123:

	2005			2004		2003
Net income (loss)—as reported	$	(685	)	$	676	$	707
Deduct: Total stock-based compensation expense under fair-value method for all awards, net of income taxes(a)		3			5		5
Pro forma net income (loss)	$	(688	)	$	671	$	702

(a) The fair value of options granted was estimated using a Black-Scholes-Merton option pricing model.

SFAS No. 153. In December 2004, the FASB issued FASB Statement No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, ‘Accounting for Nonmonetary Transactions’” (SFAS No. 153). Previously, APB Opinion No. 29 had required that the accounting for an exchange of a productive asset for a similar productive asset or an equivalent interest in the same or similar productive asset should be based on the recorded amount of the asset relinquished. The amendments made by SFAS No. 153 are based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, the amendments eliminate the narrow exception for nonmonetary exchanges of similar productive assets and replace it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance, in essence increasing the number of exchanges that will be fair valued in the future. SFAS No. 153 was effective in the third quarter of 2005. The provisions of SFAS No. 153 are applied prospectively. The adoption of this standard did not have a material impact on ComEd’s financial condition or results of operations in the third or fourth quarter of 2005.

FIN 47.In March 2005, the FASB issued FIN 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47) which clarifies that the term “conditional asset retirement obligation” as used in FASB Statement No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143), refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 was effective for ComEd as of December 31, 2005. See Note 12—Conditional ARO for further information.

SFAS No. 154.In May 2005, the FASB issued FASB Statement No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS No. 154). Previously, APB No. 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting

280

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Changes in Interim Financial Statements” required the inclusion of the cumulative effect of changes in accounting principle in net income of the period of the change. SFAS No. 154 requires companies to recognize a change in accounting principle, including a change required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements. ComEd will assess the impact of a retrospective application of a change in accounting principle in accordance with SFAS No. 154 when such a change arises after the effective date of January 1, 2006.

Cumulative Effect of Changes in Accounting Principles

FIN 47.During 2005, ComEd recorded a charge of $9 million (net of income taxes of $6 million) as a cumulative effect of a change in accounting principle pursuant to the adoption of FIN 47. The impact on ComEd’s net income for 2005, 2004 and 2003, adjusted as if FIN 47 had been applied effective during the entirety of those years would have been less than $1 million in each year. See additional discussion of the adoption of FIN 47 above.

SFAS No. 143.SFAS No. 143 provides accounting guidance for retirement obligations (whether statutory, contractual or as a result of principles of promissory estoppel) associated with tangible long-lived assets. ComEd adopted SFAS No. 143 as of January 1, 2003 and recorded income of $5 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.

2. Acquisitions and Dispositions

During 2005, ComEd’s subsidiary EDCAN and its subsidiary EFP were liquidated and are pending legal dissolution in 2006. As a result of this, the outstanding preference stock of EDCAN was redeemed. EDCAN’S and EFP’s foreign currency adjustment’s recorded in other comprehensive income were recognized in 2005 income and expense and resulted in a net gain of $1.2 million.

3. Regulatory Issues

Illinois Procurement Filing. In 2004, the ICC initiated and conducted a workshop process to consider issues related to retail electric service in the post-transition period (i.e., post 2006). Issues addressed included utility wholesale generation supply procurement methodology, rates, competition and utility service obligations and energy assistance programs. All interested parties were invited to participate. The end result was a report from the ICC to the Illinois General Assembly that was generally supportive of utilities competitively procuring generation supply through a reverse-auction process with full recovery of the supply costs from retail customers while being mindful of consumer protections. In the proposed reverse-auction model, qualified energy suppliers would compete in a transparent, fair and structured auction to provide energy to the utilities and their customers; winning bidders would provide the power needed at the price determined by the auction’s results; and the utilities would make no profit on the energy but would recover from customers the cost of procurement. The ICC staff would oversee the entire process.

On February 25, 2005, ComEd filed with the ICC seeking regulatory approval of tariffs that implement the methodologies supported by the report, including a proposal consistent with the reverse-auction process described above (the Procurement Case). As requested by ComEd, the ICC initiated hearings on the matter. The Illinois Attorney General, Citizens’ Utility Board (CUB), Cook County

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Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

State’s Attorney’s Office and the Environmental Law and Public Policy Center subsequently filed a motion to dismiss the proceeding arguing that customers whose retail service has not been declared competitive are entitled to cost-based rates for power and its delivery and that the ICC lacked authority to approve rates based on the market value of power, as proposed by ComEd. On June 1, 2005 the administrative law judge denied the motion and, on July 13, 2005, the ICC denied the appeal. On December 5, 2005, the administrative law judge issued a proposed order that recommended that the ICC approve the competitive procurement process similar to the ComEd proposal. The administrative law judge reaffirmed an earlier ruling that the ICC has legal authority under the Public Utility Act to approve an auction process and the resulting rates. The proposed order also increased the regulatory oversight of the process.

On January 24, 2006, the ICC, by a unanimous vote, approved a reverse-auction competitive bidding process for procurement of power by ComEd for the time period after 2006. The procurement process is similar to the process described in the Procurement Case and the administrative law judge’s order described above, with some modifications to enhance consumer protection. The auction will be administered by an independent auction manager, with oversight by the ICC staff. The first auction is scheduled to take place during the fall of 2006, at which time ComEd’s entire load will be up for bid. To mitigate the effects of changes in future prices, the load will be staggered in three-year contracts. To further mitigate the impact on its residential customers of transitioning to this process, ComEd has offered to develop a “cap and deferral” proposal to ease the impact of the expected increase in rates on residential customers, some or all of which could require regulatory or legislative approval to implement. A cap and deferral proposal, generally speaking, would limit the procurement costs that ComEd could pass through to its customers for a specified period of time and allow ComEd to collect any unrecovered procurement costs in later years.

Several parties that were opposed to the Procurement Case have indicated that they will petition the ICC for rehearing and will challenge the ICC decision in court. ComEd also petitioned for rehearing of the ICC decision on certain issues, but that petition was denied by the ICC on February 8, 2006. It is also possible that interested parties could introduce legislation in Illinois in an attempt to modify the procurement process or the rates that ComEd may charge consumers for the power ComEd purchases to meet the needs of consumers. The Illinois General Assembly has held hearings concerning generation procurement after 2006, and it may take action on this issue.

On September 1, 2005, the Illinois Attorney General, the Cook County State’s Attorney, CUB and the Environmental Law and Public Policy Center filed a two-count complaint in the Chancery Division of the Circuit Court of Cook County against the ICC and the individual ICC commissioners (the Procurement Litigation). The Procurement Litigation sought to block the ICC from approving the Procurement Case on the theory that the ICC lacked the authority to approve the rates because not all of the services that will be provided under the Procurement Case have been declared competitive and do not qualify for market-based rates. The legal argument underlying the Procurement Litigation is substantially similar to the legal argument that was presented to the administrative law judge, and to the ICC on appeal, and rejected by both, in the third quarter of 2005. ComEd intervened in the Procurement Litigation to deny the allegations in the complaint and sought a determination that the ICC has appropriate legal authority to approve the proposed electricity procurement process pending before the ICC in the Procurement Case. ComEd moved for summary judgment in the litigation, and the ICC moved to dismiss one claim in the litigation and for summary judgment on the other claim. A hearing on the motions was held on December 14, 2005 and the court issued a written order on January 20, 2006 denying the relief sought by the plaintiffs and dismissing the case with prejudice.

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Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

On October 17, 2005, ComEd and Exelon Generation, LLC (Generation) filed an application with the FERC seeking approval that the proposed Illinois auction process meets FERC principles and that if Generation is selected as a winning bidder in the Illinois auction, the standard agreements under which Generation would sell energy, capacity and ancillary services to ComEd would be acceptable to the FERC. On December 16, 2005, the FERC issued an order granting both requests.

In November 2005, ComEd announced several actions intended to affirm the fact that ComEd is an independent entity, separate and distinct from its parent Exelon, and to strengthen ComEd’s ability to successfully manage some potentially challenging financial and strategic issues as Illinois continues its transition to restructuring after 2006. The actions include the election of a new board of directors of ComEd and selection of senior officers. The senior officers have responsibilities solely for ComEd.

The ICC, in its Order approving the Procurement Case, also ordered its Staff to “present orders initiating three separate rulemakings regarding demand response programs, energy efficiency programs and renewable energy resources to the Commission within thirty (30) days of the entry of this Order.” ComEd intends to participate in any such rulemakings.

Illinois Rate Case. On August 31, 2005, ComEd filed a rate case with the ICC, which seeks, among other things, to allocate the costs of delivering electricity and to adjust ComEd’s rates for delivering electricity effective January 2, 2007 (Rate Case). Several intervenors in the Rate Case, including the ICC staff and the Illinois Attorney General, have suggested, and provided testimony, that ComEd’s rates should actually be reduced. The commodity component of ComEd’s rates will be established by the reverse-auction process in accordance with the ICC order in the Procurement Case, assuming the ICC order on this matter is upheld upon appeal. The results of the Rate Case are not expected to be known until at least the third quarter of 2006.

Post 2006. ComEd cannot predict the results of the Rate Case before the ICC or whether the Illinois General Assembly might take action that could have a material impact on the outcome of the regulatory process. However, if the price at which ComEd is allowed to sell energy beginning in 2007 is below ComEd’s cost to procure and deliver electricity, there may be material adverse consequences to ComEd. ComEd believes that these potential material adverse consequences could include, but may not be limited to, loss of ComEd’s investment grade credit rating and a possible reduction in other credit ratings, limited or lost access for ComEd to credit markets to finance operations and capital investment, and loss of ComEd’s capacity to enter into bilateral long-term energy procurement contracts, which would likely force ComEd to procure electricity at more volatile and potentially higher prices in the spot market. Moreover, to the extent ComEd is not permitted to recover its costs, ComEd’s ability to maintain and improve service may be diminished and its ability to maintain reliability may be impaired. In the nearer term, these prospects could have adverse effects on ComEd’s liquidity if vendors reduce credit or shorten payment terms or if ComEd’s financing alternatives become more limited and significantly less flexible. ComEd also cannot predict the long-term impact of customer choice for energy supply on its results of operations.

PJM Integration.On June 2, 2003, ComEd began receiving electric transmission reservation services from PJM Interconnection, LLC (PJM) and transferred control of ComEd’s Open Access Same Time Information System to PJM. On April 27, 2004, the FERC issued its order approving ComEd’s application to complete its integration into PJM, subject to certain stipulations. ComEd agreed to these stipulations and fully integrated its transmission facilities into PJM on May 1, 2004.

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Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Through and Out Rates / SECA.In November 2004, the FERC issued two orders authorizing ComEd to recover amounts for a limited time during a specified transitional period as a result of the elimination of through and out (T&O) rates for transmission service scheduled out of, or across, their respective transmission systems and ending within pre-expansion PJM Interconnection, LLC (PJM) or Midwest Independent System Operators (MISO) territories. T&O rates were terminated pursuant to FERC orders, effective December 1, 2004. The new rates, known as Seams Elimination Charge/Cost Adjustment/Assignment (SECA), are collected from load-serving entities within PJM and MISO over a transitional period from December 1, 2004 through March 31, 2006, subject to refund, surcharge and hearing. As a load-serving entity, ComEd is also required to pay SECA rates during the transitional period based on the benefits they receive from the elimination of T&O rates of other transmission owners within PJM and MISO.

During 2004, prior to the termination of T&O rates, ComEd collected net T&O charges of approximately $50 million. As a result of the November 2004 FERC orders and potential appeals, ComEd may see reduced net collections of SECA charges. Since the inception of the SECA rates in December 2004, ComEd has recorded approximately $44 million of SECA collections net of SECA charges, including $40 million in 2005. Management of ComEd believes that appropriate reserves have been established in the event that such SECA collections are required to be refunded. However, as the above amounts collected under the SECA rates are subject to refund and surcharge and the ultimate outcome of the proceeding establishing SECA rates is uncertain, the result of this proceeding may have a material adverse effect on ComEd’s financial condition, results of operations and cash flows.

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 ComEd’s PPA with Generation. The effect of the Agreement is to lower competitive transition charge (CTC) collections that ComEd receives from customers who take electricity from an alternative electric supplier or under the purchase power option (PPO) through 2006. The Agreement also allows customers to lock in current CTCs for multiple years. In 2005, 2004 and 2003, ComEd collected $105 million, $169 million and $304 million in CTC revenues, respectively.

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 Exelon’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 $10 million, $10 million and $23 million during 2005, 2004 and 2003, respectively.

Customer Choice.All ComEd’s retail customers are eligible to choose an alternative electric supplier and most non-residential customers may also buy electricity from ComEd at market-based prices under the PPO. One alternative supplier was approved to serve residential customers in the ComEd service territory. However, as of December 31, 2005, no residential customers have selected

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Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

this alternative supplier. As of December 31, 2005, approximately 21,300 non-residential customers, or 33% of ComEd’s annual retail kilowatthour sales, had elected either the PPO or an alternative electric supplier. 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 certain customers with energy demands of at least three 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 will not have a right to take bundled service after June 2006 or to return to bundled rates if they choose an alternative supplier prior to June 2006.

On March 28, 2003, the ICC approved changes to ComEd’s real-time pricing tariff for non-residential customers, including those with energy demands of at least three MWs, who choose hourly energy supply for their electric power and energy. The ICC orders were affirmed on appeal.

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 reduction, 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 (20 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. Under Illinois statute, any impairment of goodwill would have no impact on the determination of the cap on ComEd’s allowed equity return during the transition period. As a result of the Illinois legislation, at December 31, 2005, ComEd had a regulatory asset related to recoverable transition costs with an unamortized balance of $43 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 in amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold. ComEd has not triggered the earnings sharing provision through 2005.

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. Because ComEd did not take all of the output of these stations, actual collections were $68 million in 2005 and are expected to be a similar amount in 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. The amounts collected by ComEd from retail customers are remitted to Generation. See Note 11—Nuclear Decommissioning.

Open Access Transmission Tariff. On November 10, 2003, the FERC issued an order allowing ComEd to put into effect, 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 until January 2, 2007. During the third quarter of 2004, a settlement

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Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

agreement was reached which was approved by the FERC during the fourth quarter of 2004, which established new rates that became effective May 1, 2004.

The Energy Policy Act of 2005. The Energy Policy Act of 2005 (the Energy Policy Act), which was signed into law on August 8, 2005, implements several significant changes intended to improve electric reliability, promote investment in electric facilities, streamline electric regulation, improve wholesale competition, address problems identified in the Western energy crisis and Enron collapse, promote fuel diversity and cleaner fuel sources, and promote greater efficiency in electric generation, delivery and use.

The Energy Policy Act also transfers to FERC certain additional authority. FERC obtains new authority to review the acquisition or merger of generating facilities, along with the responsibility to address more explicitly cross-subsidization issues in these situations. FERC now has the authority to approve siting of electric transmission facilities located in national interest electric transmission corridors if states cannot or will not act in a timely manner to approve siting. The Energy Policy Act also creates a self-regulating electric reliability organization with FERC oversight to enforce reliability rules.

Additionally, the Energy Policy Act repealed PUHCA effective February 8, 2006. Since Exelon was a registered holding company under PUHCA, Exelon and its subsidiaries, including ComEd, were subject to a number of restrictions. These restrictions involved financings, investments and affiliate transactions. Exelon had an order under PUHCA authorizing financing transactions within certain limits. Exelon also had an order under PUHCA authorizing development activities, the formation of new intermediate subsidiaries for internal corporate structuring, internal corporate reorganizations, and investments in certain non-U.S. energy-related subsidiaries. PUHCA also limited the businesses in which Exelon could engage in and the investments that Exelon could make, and required that Exelon’s utility subsidiaries constituted a single system that could be operated in an efficient, coordinated manner. With the repeal of PUHCA, Exelon is no longer subject to these restrictions. However, Section 203 of the Federal Power Act as amended by the Energy Policy Act, and regulations promulgated thereunder, governs intercompany system financings and cash management arrangements, certain internal corporate reorganizations, and certain holding company acquisitions of public utility and holding company securities. FERC will obtain additional jurisdiction for the review of affiliate transactions, and FERC’s financing jurisdiction resumes to the extent that it was preempted by PUHCA. With the repeal of PUHCA, the SEC’s financing jurisdiction under PUHCA for ComEd’s short-term financings reverted to FERC. On February 3, 2006, ComEd received an order from the FERC authorizing short-term financing for an amount not to exceed $2.5 billion, effective February 8, 2006 through December 31, 2007. To the extent that the SEC’s jurisdiction under PUHCA preempted certain aspects of state regulation of Exelon, the repeal of PUHCA will permit the states in which Exelon and its subsidiaries, including ComEd, operate to adopt additional regulations if they so choose, absent any preemption by the FERC.

4. Accounts Receivable

Customer accounts receivable at December 31, 2005 and 2004 included estimated unbilled revenues associated with unread meters, representing an estimate for the unbilled amount of energy or services provided to customers, and allowance for uncollectible accounts as follows:

	2005		2004
Unbilled revenues	$	287	$	275
Allowance for uncollectible accounts		20		16

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Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

5. Property, Plant and Equipment

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2005 and 2004:

	December 31,
Asset Category	2005		2004
Electric—transmission and distribution	$	9,579	$	8,978
Construction work in progress		253		195
Asset retirement cost(a)		25		—
Other property, plant and equipment		1,302		1,298
Total property, plant and equipment		11,159		10,471
Less accumulated depreciation		1,253		1,008
Property, plant and equipment, net		9,906		9,463

(a) See Note 12—Conditional ARO for further information.

ComEd’s depreciation expense, which is included in cost of service for rate purposes, includes the estimated cost of dismantling and removing plant from service upon retirement. Collections for future removal costs are recorded as a regulatory liability. For more information, see Note 18—Supplemental Financial Information.

6. Goodwill

Pursuant to SFAS No. 142, goodwill is not 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 requires unrecognized intangible assets to be valued and then 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.

The changes in the carrying amount of goodwill for the years ended December 31, 2005 and 2004 were as follows:

Balance as of January 1, 2004	$	4,719
Resolution of certain tax matters(a)		(9	)
PECO / Unicom Merger severance adjustments		(5	)
Balance as of January 1, 2005		4,705
Resolution of certain tax matters		(23	)
Impairment		(1,207	)
Balance as of December 31, 2005	$	3,475

(a) Adjustment related to income tax refund claims and interest thereon. See Note 17—Commitments and Contingencies for further information.

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Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

2005 Annual Goodwill Impairment Assessment.The annual goodwill impairment assessment was performed as of November 1, 2005. The first step of the annual impairment analysis, comparing the fair value of a reporting unit to its carrying value, including goodwill, indicated an impairment of goodwill existed. The second step of the analysis indicated ComEd’s goodwill was impaired by $1.2 billion. This impairment was primarily driven by the fair value of ComEd’s below market purchase power agreement with Generation, the end of ComEd’s regulatory transition period at December 31, 2006 and the elimination of related transition revenues, developments in the regulatory and political environment as of November 1, 2005, anticipated increases in capital expenditures in future years, and decreases in market valuations of comparable companies that are used to estimate the fair value of ComEd. In its assessment to estimate the fair value of its goodwill, 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, capital structure, market prices for power, post 2006 rate regulatory structures, operating and capital expenditure requirements and other factors.

Changes from the assumptions used in the impairment review could possibly result in a future impairment loss of ComEd’s goodwill, which could be material. Illinois legislation provides that reductions to ComEd’s common equity resulting from goodwill impairments will have no impact on the determination of the rate cap on ComEd’s allowed equity return during the electricity industry restructuring transition period through 2006. See Note 3—Regulatory Issues for further discussion of ComEd’s earnings provisions.

2004 Annual Goodwill Impairment Assessment.The annual goodwill impairment assessment was performed as of November 1, 2004. The first step of the annual impairment analysis, comparing the fair value of a reporting unit to its carrying value, including goodwill, indicated no impairment of goodwill. In its assessment to estimate the fair value of its reporting unit, ComEd used probability-weighted, discounted cash flow models with multiple scenarios. The determination of the fair value was dependent on many sensitive, interrelated and uncertain variables including changing interest rates, utility sector market performance, capital structure, market prices for power, post 2006 rate regulatory structures, operating and capital expenditure requirements and other factors.

7. Severance Accounting

ComEd provides severance and health and welfare benefits to terminated employees pursuant to pre-existing severance plans maintained by Exelon primarily based upon each individual employee’s years of service and compensation level. ComEd accounts for its ongoing severance plans in accordance with SFAS No. 112 and SFAS No. 88 and accrues amounts associated with severance benefits that are considered probable and that can be reasonably estimated.

The following tables present total salary continuance severance costs (benefits), recorded as an operating and maintenance expense, during 2005, 2004 and 2003:

Salary Continuance Severance
Income recorded—2005(a)	$	(9	)
Expense recorded—2004		10
Expense recorded—2003		61

(a) Represents a reduction in previously recorded severance reserves.

288

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

The following table provides a roll forward of the salary continuance severance obligations from January 1, 2004 through December 31, 2005:

Salary continuance severance obligations
Balance at January 1, 2004	$	55
Severance charges recorded		10
Cash payments		(34	)
Other adjustments		(3	)
Balance at January 1, 2005	$	28
Reduction in obligation estimate		(9	)
Cash payments		(11	)
Balance at December 31, 2005	$	8

8. Short-Term Debt

	2005			2004			2003
Average borrowings	$	36		$	7		$	4
Maximum borrowings outstanding		497			180			123
Average interest rates, computed on a daily basis		4.13	%		2.11	%		1.47	%
Average interest rates, at December 31		4.50	%		—			—

At December 31, 2003, Exelon, along with ComEd, PECO and Generation, participated with a group of banks in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion unsecured revolving facility maturing on July 16, 2009, and the $750 million three-year facility was reduced to $500 million maturing on October 31, 2006. 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.

At December 31, 2005, ComEd had the following sublimits and available capacity under the credit agreements and the indicated amounts of outstanding commercial paper:

	Bank Sublimit (a)		Available Capacity (b)		Outstanding Commercial Paper
ComEd	$	650	$	623	$	459

(a) Sublimits under the credit agreements can change upon written notification to the bank group.

(b) Available capacity represents the bank sublimit net of outstanding letters of credit. The amount of commercial paper outstanding does not reduce the available capacity under the credit facilities.

Interest rates on advances under the credit facilities are based on either prime or the London Interbank Offering Rate (LIBOR) 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 LIBOR adder is 170 basis points.

The credit agreements require ComEd to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratios exclude

289

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries. For the twelve-month period ended December 31, 2005, ComEd’s minimum cash from operations to interest expense ratio was 2.25 to 1. At December 31, 2005, ComEd was in compliance with this threshold.

9. Long-Term Debt

	Rates	Maturity Date	December 31,
			2005			2004
Long-term debt
First Mortgage Bonds(a) (b):
Fixed rates	3.70%-8.375%	2006-2033	$	2,201		$	2,509
Floating rates	3.05%-3.40%	2013-2020		343			252
Notes payable
Fixed rates	6.95%-7.625%	2006-2018		285			392
Sinking fund debentures	3.875%-4.75%	2008-2011		10			12
Total long-term debt(c)				2,839			3,165
Unamortized debt discount and premium, net				(16	)		(15	)
Unamortized settled fair value hedge				6			14
Fair-value hedge carrying value adjustment, net				(1	)		9
Long-term debt due within one year				(328	)		(272	)
Long-term debt			$	2,500		$	2,901
Long-term debt to financing trusts(d)
Subordinated debentures to ComEd Financing II(e)	8.50%	2027		155			155
Subordinated debentures to ComEd Financing III(e)	6.35%	2033		206			206
Payable to ComEd Transitional Funding Trust(e)	5.44%-5.74%	2006-2008		987			1,341
Total long-term debt to affiliates(e)				1,348			1,702
Long-term debt to financing trusts due within one year				(307	)		(321	)
Total long-term debt to financing trusts			$	1,041		$	1,381

(a) ComEd’s utility plant is subject to the lien of its mortgage indenture.

(b) Includes first mortgage bonds issued under the ComEd mortgage indentures securing pollution control bonds and notes.

(c) Long-term debt maturities in the periods 2006 through 2010 and thereafter are as follows:

Year
2006	$	328
2007		147
2008		417
2009		17
2010		213
Thereafter		1,717
Total	$	2,839

(d) Effective December 31, 2003, ComEd Financing II, ComEd Financing III, and ComEd Transitional Funding Trust were deconsolidated from the financial statements in conjunction with the adoption of FIN 46-R. Amounts owed to these financing trusts are recorded as debt to financing trusts within ComEd’s Consolidated Balance Sheets.

290

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

(e) Long-term debt to financing trusts maturities in the periods 2006 through 2010 and thereafter are as follows:

Year
2006	$	307
2007		340
2008		340
2009		—
2010		—
Thereafter		361
Total	$	1,348

Issuances of Long-Term Debt. The following long-term debt was issued during 2005:

ComEd Pollution Control Revenue Bonds Variable March 1, 2017 $ 91

(a) Issuances exclude unamortized bond discounts.

Debt Retirements and Redemptions.The following debt was retired, through tender, open market purchases, optional redemption or payment at maturity, during 2005:

Company	Type	Interest Rate		Maturity	Amount
ComEd	Pollution Control Revenue Bonds	6.75	%	March 1, 2015	$	91
ComEd	First Mortgage Bonds	9.88	%	June 15, 2020		54
ComEd	First Mortgage Bonds	7.00	%	July 1, 2005		163
ComEd	Notes Payable	6.40	%	October 15, 2005		107
ComEd	Sinking Fund Debentures	3.88	%	January 1, 2008		1
ComEd	Sinking Fund Debentures	4.75	%	January 1, 2011		1
Total retirements					$	417

During 2005 and 2004, ComEd made scheduled payments of $354 million and $335 million, respectively, related to its obligation to the ComEd Transitional Funding Trust. Prepayment premiums of $2 million, unamortized discount of $2 million and debt issuance costs of $1 million associated with the early retirement of debt in 2005 have been deferred in ComEd’s regulatory assets and will be amortized to interest expense over the life of the related new debt issuance consistent with regulatory recovery.

During 2004, ComEd retired $1.2 billion of long-term debt, including $1.0 billion prior to its maturity and $206 million at maturity, pursuant to Exelon’s accelerated liability management plan. ComEd funded the retirements through cash from operations, a return of contributions to the intercompany money pool and collections on an intercompany note receivable from UII, LLC (formerly Unicom Investments, Inc.). ComEd recorded charges of $130 million (before income taxes) in 2004 associated with the retirement of debt under the plan. The components of these charges included the following: $86 million of prepayment premiums; $12 million of net unamortized premiums, discounts and debt issuance costs; $24 million of losses on reacquired debt previously deferred as regulatory assets; and $12 million of settled cash-flow interest-rate swaps previously deferred as regulatory assets partially offset by $4 million of unamortized gain on settled fair value interest-rate swaps.

291

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

See Note 14—Fair Value of Financial Assets and Liabilities for additional information regarding interest-rate swaps of ComEd.

See Note 15—Preferred Securities for additional information regarding preferred stock.

10. Income Taxes

ComEd’s income tax expense (benefit) is comprised of the following components:

	For the Year Ended December 31,
	2005			2004			2003
Included in operations:
Federal
Current	$	112		$	231		$	362
Deferred		187			147			19
Investment tax credit amortization		(3	)		(3	)		(3	)
State
Current		25			73			96
Deferred		42			9			(9	)
Total income tax expense	$	363		$	457		$	465

Included in cumulative effect of changes in accounting principles:

Deferred
Federal	$	(5	)	$	—	$	—
State		(1	)		—		—
Total income tax expense (benefit)	$	(6	)	$	—	$	—

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

	For the Year Ended December 31,
	2005		2004		2003
U.S. Federal statutory rate	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	(13.6	)	4.8		4.8
Amortization of regulatory asset	(2.1	)	0.6		0.5
Amortization of investment tax credit	1.0		(0.3	)	(0.3	)
Nontaxable postretirement benefits	1.0		(0.2	)	—
Plant basis differences	—		—		(0.2	)
Nondeductible goodwill impairment charge	(135.0	)	—		—
Other	(2.3	)	0.4		—
Effective income tax rate	(116.0	)%	40.3	%	39.8	%

292

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Excluding the goodwill impairment, which is a non taxable item, ComEd’s effective income tax rate varies from the U.S. Federal statutory rate principally due to the following:

	For the Year Ended December 31,
	2005		2004		2003
U.S. Federal statutory rate	35.0%		35.0%		35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	4.8		4.8		4.8
Amortization of regulatory asset	0.7		0.6		0.5
Amortization of investment tax credit	(0.3	)	(0.3	)	(0.3	)
Nontaxable postretirement benefits	(0.3	)	(0.2	)	—
Plant basis differences	—		—		(0.2	)
Other, net	0.7		0.4		—
Effective income tax rate excluding goodwill impairment	40.6%		40.3%		39.8%

The tax effect of temporary differences giving rise to significant portions of ComEd’s deferred tax assets and liabilities as of December 31, 2005 and 2004 are presented below:

	2005			2004
Deferred tax liabilities:
Plant basis difference	$	(1,891	)	$	(1,890	)
Deferred debt refinancing costs		(34	)		(39	)
Deferred pension and postretirement obligations		(281	)		—
Other, net(a)		—			(6	)
Total deferred tax liabilities		(2,206	)		(1,935	)
Deferred tax assets:
Deferred pension and postretirement obligations		—			30
Other, net		72			—
Total deferred tax assets		72			30
Deferred income tax liabilities (net) on the Consolidated Balance Sheets	$	(2,134	)	$	(1,905	)

(a) As of December 31, 2004, includes $2 million of deferred income tax assets included in other noncurrent assets in ComEd’s Consolidated Balance Sheets.

In 2005 and 2004, ComEd received $27 million and $55 million, respectively from Exelon related to its allocation of tax benefits under the Tax Sharing Agreement.

In accordance with regulatory treatment of certain temporary differences, ComEd has recorded a net regulatory asset associated with deferred income taxes, pursuant to SFAS No. 71 and SFAS No. 109, of $8 million and $4 million at December 31, 2005 and 2004, respectively. See Note 18— Supplemental Financial Information for further discussion of ComEd’s regulatory asset associated with deferred income taxes.

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

293

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

1999 Sale of Fossil Generating Assets

ComEd has taken certain tax positions, which have been disclosed to the IRS, to defer the tax gain on the 1999 sale of its fossil generating assets. As of December 31, 2005 and 2004, deferred tax liabilities related to the fossil plant sale are reflected in Exelon’s Consolidated Balance Sheets with the majority allocated to ComEd and the remainder to Generation. ComEd’s ability to continue to defer all or a portion of this liability depends on whether its treatment of the sales proceeds as having been received in connection with an involuntary conversion is proper pursuant to applicable law. ComEd’s ability to continue to defer the remainder of this liability may depend in part on whether its tax characterization of a lease transaction ComEd entered into in connection with the sale is proper pursuant to applicable law. For instance, the IRS may argue that the lease transaction is of a type it has recently announced its intention to challenge, and ComEd understands that somewhat similar transactions entered into by other companies have been the subject of review and challenge by the IRS. A successful IRS challenge to ComEd’s positions would have the impact of accelerating future income tax payments and increasing interest expense related to the deferred tax gain that becomes currently payable. As of December 31, 2005, ComEd’s potential cash outflow, including tax and interest (after tax), could be as much as $951 million. If the deferral were successfully challenged by the IRS, it could negatively impact ComEd’s results of operations by as much as $135 million (after tax). ComEd’s management believes a reserve for interest has been appropriately recorded in accordance with FASB Statement No. 5, “Accounting for Contingencies” (SFAS No. 5); however, the ultimate outcome of such matters could result in unfavorable or favorable adjustments to the results of operations, and such adjustments could be material. Federal tax returns covering the period of the 1999 sale are currently under IRS audit. Final resolution of this matter is not anticipated for several years.

11. Nuclear Decommissioning

As a result of corporate restructuring in 2001, assets and liabilities associated with nuclear power plants previously owned by ComEd were transferred to Generation. Pursuant to the Nuclear Regulatory Commission (NRC) regulations, Generation has an obligation to decommission these nuclear power plants. Based on the actual or anticipated extended license lives of the nuclear plants, expenditures are expected to begin after 2029 for plants currently in operation. Generation currently recovers costs for decommissioning nuclear generating stations, previously owned by ComEd, through regulated rates collected by ComEd. The amounts recovered from customers are deposited in trust accounts by Generation and invested for funding of future decommissioning costs of these nuclear generating stations.

ComEd currently recovers in revenues funds for decommissioning the former ComEd nuclear plants through regulated rates. The amounts recovered from customers are remitted to Generation and deposited into the trust accounts to fund the future decommissioning costs. Under a December 2000 ICC order issued to ComEd, amended February 2001 (ICC Order), ComEd is permitted to collect up to $73 million annually through 2006 from customers to decommission the former ComEd nuclear plants. The amount of decommissioning revenue collected for 2005 was $68 million and is expected to be a similar amount in 2006. Under the current ICC order related to decommissioning, ComEd will not collect amounts for decommissioning subsequent to 2006.

Based on the provisions of the ICC order and NRC regulations, Generation is financially responsible for the decommissioning obligations related to these plants. If trust assets plus future

294

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

collections permitted by the ICC order are exceeded by the ultimate asset retirement obligation (ARO), Generation is responsible for any shortfall in funding; however, if amounts remain in the trust funds for these units following the completion of the decommissioning activities, those amounts will be returned to the ComEd customers. This analysis is performed on a plant-by-plant basis. At the end of each financial reporting period, Generation assesses the amounts currently recorded in trust assets plus future collections less amounts recorded in the ARO. At December 31, 2005 and 2004, ComEd recorded a regulatory liability of $1,435 million and $1,433 million, respectively, for the amount of decommissioning-related assets in excess of the ARO.

12. Conditional ARO

As of December 31, 2005, ComEd adopted FIN 47, which clarified that a legal obligation associated with the retirement of a long-lived asset whose timing and/or method of settlement are conditional on a future event is within the scope of SFAS No. 143. Under FIN 47, ComEd is required to record liabilities associated with its conditional AROs at their estimated fair values if those fair values can be reasonably estimated.

Determination of Conditional AROs

The adoption of FIN 47 required ComEd to update an existing inventory, originally created for the adoption of SFAS No. 143, and to determine which, if any, of the conditional AROs could be reasonably estimated. The significant conditional AROs identified by ComEd included abatement and disposal of equipment and buildings contaminated with asbestos and Polychlorinated Biphenyls (PCBs).

The ability to reasonably estimate a conditional ARO was a matter of management judgment, based upon management’s ability to estimate a settlement date or range of settlement dates, a method or potential method of settlement and probabilities associated with the potential dates and methods of settlement of its conditional AROs. In determining whether their conditional AROs could be reasonably estimated, management considered past practices, industry practices, management’s intent and the estimated economic lives of the assets. The management of ComEd concluded that all significant conditional AROs could be reasonably estimated.

ComEd was required to measure the conditional AROs at fair value using the methodology prescribed by FIN 47. The transition provisions of FIN 47 required ComEd to apply this measurement back to the historical periods in which the conditional AROs were incurred, resulting in a remeasurement of these obligations at the latter of the date that the related assets were placed into service or acquired or the date that the applicable law or environmental regulation became effective. The fair values of the conditional AROs were then estimated using a probability-weighted, discounted cash flow model with multiple scenarios, if applicable. The present value of future estimated cash flows was calculated using credit-adjusted, risk-free rates applicable to ComEd in order to determine the fair value of the conditional AROs at the time of adoption of FIN 47.

Conditional AROs of $150 million were recorded as of December 31, 2005 by ComEd. Changes in management’s assumptions regarding settlement dates, settlement methods or assigned probabilities could have had a material effect on the liabilities recorded at December 31, 2005 as well as the associated cumulative effect of a change in accounting principle and the associated regulatory assets recorded.

295

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Effect of Adopting FIN 47

FIN 47 required that ComEd recognize the following amounts within its financial statements upon the adoption of FIN 47: (i) a liability for any existing conditional AROs adjusted for cumulative accretion to December 31, 2005; (ii) an asset retirement cost (ARC) capitalized as an increase to the carrying amount of the associated long-lived assets; and (iii) cumulative depreciation on the ARC. The transition guidance in FIN 47 required that its adoption be effected through a cumulative change in accounting principle measured as the difference between the amounts recognized in the financial statements prior to the adoption of FIN 47 for conditional AROs and the amounts recognized as of December 31, 2005 pursuant to FIN 47. ComEd had previously recognized $39 million as removal costs within regulatory liabilities associated with conditional AROs that were reclassified to a conditional ARO liability upon the adoption of FIN 47.

After considering the transitional guidance included in FIN 47, ComEd recorded a charge of $9 million (net of income taxes of $6 million) as a cumulative effect of a change in accounting principle in connection with its adoption. In addition, due to the application of SFAS No. 71, which is further described in Note 1—Significant Accounting Policies, ComEd recorded regulatory assets of $91 million associated with the adoption of FIN 47.

The following presents the line items within ComEd’s Consolidated Statements of Income for the year ended December 31, 2005 and the Consolidated Balance Sheets at December 31, 2005 that were affected by the adoption of FIN 47:

Consolidated statements of income line item:
Cumulative effect of a change in accounting principle (net of income taxes of $(6))(a)	$	(9	)
Consolidated balance sheets line items—increase (decrease):
Property, plant and equipment, net(b)		5
Deferred income taxes (noncurrent liability)		(6	)
Asset retirement obligations(c)		150
Regulatory liabilities(d)		(130	)

(a) Represents the difference between the conditional ARO, net ARC and regulatory assets and liabilities recorded upon adoption, net of income taxes.

(b) Represents capitalized ARC of $25 million as an increase to the carrying amount of the associated long-lived assets, net of accumulated depreciation of $20 million on the ARC.

(c) Represents a liability for existing conditional AROs adjusted for cumulative accretion to December 31, 2005.

(d) Represents an increase to regulatory assets (which are netted with regulatory liabilities) of $91 million pursuant to SFAS No. 71 for amounts expected to be recovered from customers and removal costs within regulatory liabilities of $39 million that were reclassified to the asset retirement obligations liability.

As noted in Note 1—Significant Accounting Policies, the impact on net income for 2005, 2004 and 2003, adjusted as if FIN 47 had been applied effective during the entirety of those years, would have been less than $1 million annually. The following table presents, on a pro forma basis, what the liability for conditional AROs would have been had FIN 47 been applied during the years 2004 and 2003. These pro forma amounts are estimated based upon the information, assumptions, and interest rates used to measure the liability for conditional AROs recognized upon adoption of FIN 47 as of December 31, 2005.

Pro forma liability for conditional AROs, January 1, 2003	$	125
Pro forma liability for conditional AROs, December 31, 2003		133
Pro forma liability for conditional AROs, December 31, 2004		141

296

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Prospective Accounting Methodology Under FIN 47

The liabilities associated with conditional AROs will be adjusted on an ongoing basis due to the passage of time, new laws and regulations and revisions to either the timing or amount of the original estimates of undiscounted cash flows. These adjustments could have a significant impact on ComEd’s Consolidated Balance Sheets, assuming the provisions of SFAS No. 71 continue to apply.

The liabilities recorded as of December 31, 2005 related to the conditional AROs of ComEd will be accreted to their full estimated settlement amounts through the estimated ultimate settlement dates. Most of this accretion charge will be recorded as an increase to ComEd’s regulatory assets due to the application of SFAS No. 71.

The net ARC recorded as of December 31, 2005 by ComEd will be depreciated over the remaining lives of the related long-lived assets. Most of this charge will be recorded as an increase to ComEd’s regulatory assets due to the application of SFAS No. 71.

13. Retirement Benefits

Exelon sponsors defined benefit pension plans and postretirement welfare benefit plans for essentially all ComEd employees. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in Exelon-sponsored cash balance pension plans. Substantially all non-union employees hired prior to January 1, 2001 were offered a choice to remain in Exelon’s traditional pension plan or transfer to a cash balance pension plan for management employees. The costs of providing benefits under these plans are dependent on historical information, such as employee age, length of service and level of compensation, and the actual rate of return on plan assets, in addition to 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 prepaid pension asset and non-pension postretirement benefits obligation on ComEd’s Consolidated Balance Sheets reflect ComEd’s obligations from and to the plan sponsor, Exelon. Employee-related assets and liabilities, including both pension and SFAS No. 106, 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.

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

Approximately $62 million, $86 million and $83 million were included in capital and operating and maintenance expense, excluding curtailment and special termination benefit costs, in 2005, 2004 and 2003, respectively, for ComEd’s allocated portion of Exelon’s pension and postretirement benefit expense. The 2005 and 2004 amounts reflect an annualized reduction in net periodic post-retirement benefit cost of $13 million and $11 million, respectively, related to a Federal subsidy provided under the Prescription Drug Act. This subsidy has been accounted for under FSP FAS 106-2, as described in Note 1—Significant Accounting Policies. ComEd contributed $865 million, $244 million and $201 million to the Exelon-sponsored plans in 2005, 2004 and 2003, respectively. Of ComEd’s total 2005 contributions, $803 million was made in the first quarter and was fully funded by a capital contribution from Exelon. ComEd does not expect to contribute to Exelon’s pension benefit plans in 2006.

297

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

During 2005, ComEd recognized no curtailment charges or special termination benefit costs. During 2004 and 2003, ComEd recognized curtailment charges of $3 million and $48 million (before income taxes), respectively, associated with an overall reduction in participants in Exelon’s pension and postretirement benefit plans due to employee reductions. During 2004 and 2003, ComEd recognized special termination benefit costs of $8 million and $28 million (before income taxes), respectively.

ComEd participates in a 401(k) savings plan sponsored by Exelon. The plan allows employees to contribute a portion of their pre-tax 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 $17 million, $16 million and $19 million in 2005, 2004 and 2003, respectively.

14. Fair Value of Financial Assets and Liabilities

Non-Derivative Financial Assets and Liabilities

Fair Value.As of December 31, 2005 and 2004, ComEd’s carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities are representative of fair value because of the short-term nature of these instruments. Fair values for long-term debt and preferred securities of subsidiaries are determined by an external valuation model which is based on conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves.

The carrying amounts and fair values of ComEd’s financial liabilities as of December 31, 2005 and 2004 were as follows:

	2005				2004
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	2,828	$	2,887	$	3,173	$	3,363
Long-term debt to ComEd
Transitional Funding Trust (including amounts due within one year)		987		1,003		1,341		1,403
Long-term debt to other financing trusts		361		353		361		380

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

298

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Interest-Rate Swaps

The fair values of ComEd’s interest-rate swaps are determined using quoted exchange prices. At both December 31, 2005 and 2004, ComEd had $240 million of notional amounts of interest-rate swaps outstanding. At December 31, 2005 and 2004, net deferred gains (losses) associated with the interest-rate swaps were as follows:

	Notional Amount		ComEd Pays	Counterparty Pays	Fair Value 12/31/05			Fair Value 12/31/04
Fair-Value Hedges
ComEd	$	240	3 Month LIBOR plus 1.12% – 1.60%	6.15%	$	(1	)	$	9
Net Deferred Gains (Losses)					$	(1	)	$	9

Fair-Value Hedges. ComEd utilizes fixed-to-floating interest-rate swaps as a means to achieve its targeted level of variable-rate debt as a percent of total debt. At December 31, 2005, ComEd had $240 million of notional amounts of fair-value hedges outstanding. The swaps have been designated as fair-value hedges, as defined in SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133), and, as such, changes in the fair value of the swaps are 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 are 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 is recorded immediately in earnings.

During 2004, ComEd settled interest-rate swaps in aggregate notional amounts of $485 million and recorded a net pre-tax gain of $26 million, which is being amortized as a reduction to interest expense over the remaining life of the related debt. ComEd did not have any amount excluded from the measure of effectiveness for the years ended December 31, 2005 or 2004.

Cash-Flow Hedges. ComEd utilizes interest rate derivatives to lock in interest-rate levels in anticipation of future financings. Forward-starting interest-rate swaps are designated as cash-flow hedges, as defined in SFAS No. 133 and, as such, changes in the fair value of the swaps are recorded in accumulated other comprehensive income (OCI). Any change in the fair value of the hedge as a result of ineffectiveness is recorded immediately in earnings. At December 31, 2005, ComEd did not have any notional amounts of cash-flow hedges outstanding. However, during 2005, as a result of a forecasted transaction no longer being probable, ComEd settled interest-rate swaps in the aggregate notional amount of $325 million and recorded net pre-tax losses of $15 million which were included in other, net within ComEd’s Consolidated Statements of Income.

Credit Risk Associated with Derivative Instruments. ComEd would be exposed to credit-related losses in the event of non-performance by counterparties that issue derivative instruments. The credit exposure of derivative contracts is represented by the fair value of contracts at the reporting date. The notional amount of derivatives does 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.

299

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

15. Preferred Securities

Preferred and Preference Stock of Subsidiaries

At December 31, 2005 and 2004, ComEd prior preferred stock and ComEd cumulative preference stock consisted of 850,000 shares and 6,810,451 shares authorized, respectively, none of which was outstanding.

At December 31, 2004, ComEd had 1,120 non-cumulative preference shares outstanding with a book value of $7 million. During 2005, ComEd redeemed all outstanding preference shares of its subsidiary EDCAN at their book value.

16. Common Stock

At December 31, 2005 and 2004, ComEd’s common stock with a $12.50 par value consisted of 250,000,000 and 250,000,000 shares authorized, respectively, and 127,016,519 and 127,016,502 shares outstanding, respectively. At December 31, 2005 and 2004, ComEd had 75,720 and 75,927 warrants, respectively, 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, 2005 and 2004, 25,240 and 25,309 shares of common stock were reserved for the conversion of warrants.

Undistributed Losses of Equity Method Investments

ComEd had undistributed losses of equity method investments of $38 million and $21 million at December 31, 2005 and 2004, respectively.

17. Commitments and Contingencies

Energy Commitments

Under the PPA, as amended, between ComEd and Generation, Generation has agreed to supply substantially all of ComEd’s load requirements through 2006. Prices for this energy vary depending upon the time of day and month of delivery. Subsequent to 2006, ComEd expects to procure all of its supply from market sources, which could include Generation. See Note 3 of ComEd’s Consolidated Financial Statements for further regulatory information.

300

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Commercial Commitments

ComEd’s commercial commitments as of December 31, 2005, representing commitments potentially triggered by future events, were as follows:

			Expiration within
	Total		2006		2007-2008		2009-2010		2011 and beyond
Letters of credit (non-debt)(a)	$	27	$	27	$	—	$	—	$	—
Midwest Generation Capacity Reservation Agreement guarantee(b)		25		4		8		8		5
Other		7		7		—		—		—
Total commercial commitments	$	59	$	38	$	8	$	8	$	5

(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 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 has agreed to reimburse Chicago for any nonperformance by Midwest Generation under the Capacity Reservation Agreement. Under FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others” (FIN 45), $3 million is included as a liability on ComEd’s Consolidated Balance Sheets at December 31, 2005.

Environmental Issues

General.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 contamination by substances that 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 identified by ComEd, the Illinois Environmental Protection Agency has approved the clean up of six sites. Of the remaining sites identified by ComEd, 22 sites are currently under some degree of active study and/or remediation. In addition, 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, 2005 and December 31, 2004, ComEd had accrued the following amounts for environmental liabilities:

	December 31, 2005			December 31, 2004
Total environmental investigation and remediation reserve	$	54		$	61
Portion of total related to MGP investigation and remediation		48	(a)		55	(b)

(a) Recorded on a discounted basis, reflecting a discount rate of 4.0%. Estimate before the effects of discounting was $54 million, which reflects an inflation rate of 2.3%.

(b) Recorded on a discounted basis, reflecting a discount rate of 4.3%. Estimate before the effects of discounting was $60 million, which reflects an inflation rate of 2.3%.

301

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

As of December 31, 2005, ComEd anticipates that payments related to the discounted environmental investigation and remediation costs, disclosed below on an undiscounted basis, will be:

2006	$	5
2007		11
2008		11
2009		11
2010		4
Remaining years		12
Total payments	$	54

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, including customers. See Note 18—Supplemental Financial Information for further information regarding regulatory assets and liabilities.

Leases

Minimum future operating lease payments, including lease payments for vehicles, real estate, computers, rail cars and office equipment, as of December 31, 2005 were:

2006	$	16
2007		18
2008		19
2009		16
2010		14
Remaining years		70
Total minimum future lease payments	$	153

ComEd’s rental expense under operating leases totaled $16 million, $22 million and $17 million in 2005, 2004 and 2003, respectively.

Litigation

Rate Case.As part of its current rate case ComEd has requested recovery of amounts, which have previously been recorded as expense. Specifically, ComEd has requested recovery through rates of the $104 million (pre-tax) net loss on extinguishment of long-term debt as part of ComEd’s 2004 Accelerated Liability Management Plan. Additionally, ComEd is seeking a new rider to recover environmental clean up costs that will occur after the transition period is over. These amounts are currently included in ComEd’s liability for environmental investigation and remediation costs, which totaled $54 million as of December 31, 2005. As discussed in Note 3—Regulatory Issues, ComEd anticipates receiving a final order associated with the rate case during the third quarter of 2006. If the order affirms these requests, ComEd will recognize a one-time benefit to reverse these prior charges.

General. ComEd is involved in various litigation matters that are being defended and handled in the ordinary course of business. ComEd maintains accruals for such costs that are probable of being

302

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

incurred and subject to reasonable estimation. The ultimate outcomes of such matters, as well as the matters discussed above, are uncertain and may have a material adverse effect on ComEd’s financial condition, results of operations or cash flows.

Fund Transfer Restrictions

Under applicable Federal law, ComEd can pay dividends only from retained, undistributed or current earnings. Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “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 that 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, 2005 and 2004, ComEd had retained earnings (deficits) of $(81) million and $1,102 million, respectively. The 2005 balance consists of $1,099 million of retained earnings appropriated for future dividends offset by unappropriated retained deficits of $(1,180) million.

Income Taxes

Refund Claims.ComEd has entered into several agreements with a tax consultant related to the filing of refund claims with the IRS. ComEd previously made refundable prepayments to the tax consultants of $11 million. The fees for these agreements are contingent upon a successful outcome of the claims and are based upon a percentage of the refunds recovered from the IRS, if any. The ultimate net cash outflow from 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 the financial position, results of operations and cash flows of ComEd. A portion of ComEd’s tax benefits, including any associated interest for periods prior to the PECO / Unicom Merger, would be recorded as a reduction of goodwill pursuant to a reallocation of the PECO / Unicom Merger purchase price.

In 2004, the IRS granted preliminary approval for one of ComEd’s refund claims and final approval was obtained in the first quarter of 2005. The refund and associated interest have been recorded in the consolidated financial statements. Approximately $14 million of tax and interest benefit received in the second quarter of 2005 has been reflected in the consolidated financial statements of which $12 million ($9 million after tax) was recorded to goodwill under the provisions of EITF Issue 93-7, “Uncertainties Related to Income Taxes in a Purchase Business Combination.” As a result, ComEd recorded consulting expenses of $5 million (pre-tax) in 2004.

Other Refund Claims. ComEd has filed several tax refund claims with Federal and state taxing authorities. ComEd is unable to estimate the ultimate outcome of these refund claims and will account for any amount received in the period the matters are settled with the Federal and state taxing authorities. To the extent ComEd is successful on any of its refund claims a portion of the tax and interest benefit will be recorded to goodwill under the provisions of EITF Issue 93-7, “Uncertainties Related to Income Taxes in a Purchase Business Combination.”

303

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Other.ComEd has taken certain tax positions, which have been disclosed to the IRS to defer the tax gain on the 1999 sale of its fossil generating assets. See Note 10–Income Taxes for further information.

18. Supplemental Financial Information

Supplemental Income Statement Information

The following tables provide additional information about ComEd’s Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003.

	For the Years Ended December 31,
	2005		2004		2003
Depreciation and amortization
Property, plant and equipment(a)	$	368	$	366	$	342
Regulatory assets		45		44		44
Total depreciation and amortization	$	413	$	410	$	386

(a) Includes amortization of capitalized software costs.

	For the Years Ended December 31,
	2005		2004		2003
Taxes other than income
Utility(a)	$	247	$	234	$	233
Real estate		29		29		29
Payroll		21		21		24
Other		6		7		(19	)(b)
Total taxes other than income	$	303	$	291	$	267

(a) Municipal and state utility taxes are also recorded in revenues on ComEd’s Consolidated Statements of Income.

(b) Includes a credit of $25 million in 2003 due to a favorable settlement of coal use tax issues at ComEd related to periods prior to the PECO / Unicom Merger.

	For the Years Ended December 31,
	2005			2004		2003
Other, net
Investment income	$	3		$	3	$	4
Gain on disposition of assets and investments, net		6			3		4
Loss on settlement of cash-flow interest-rate swaps		(15	)		—		—
AFUDC, equity		5			3		9
Reserve for potential plant disallowance		—			—		12
Other		5			5		(5	)
Total other, net	$	4		$	14	$	24

304

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Supplemental Cash Flow Information

As a result of adopting FIN 47 as of December 31, 2005, ComEd recorded a net ARC of $5 million, which was capitalized as an increase to the carrying amount of long-lived assets associated with liabilities recorded for conditional AROs. This amount resulted in a non-cash investing activity. See Note 12—Conditional ARO for additional information on the adoption of FIN 47. In addition to this non-cash activity, the following table provides additional information about ComEd’s Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003.

	For the Years Ended December 31,
	2005		2004		2003
Cash paid during the year
Interest (net of amount capitalized)	$	272	$	357	$	352
Income taxes (net of refunds)		278		356		579
Non-cash investing and financing
Resolution of certain tax matters and Merger severance adjustments	$	23	$	14	$	8
Adoption of SFAS No. 143—adjustment to other paid in capital and goodwill		—		—		210

Supplemental Balance Sheet Information

The following table provides additional information about liabilities recorded within ComEd’s Consolidated Balance Sheets as of December 31, 2005 and 2004.

	December 31,
	2005		2004
Accrued expenses
Taxes accrued	$	106	$	265
Interest accrued		209		194
Other		102		130
Total accrued expenses	$	417	$	589

The following table provides additional information about accumulated other comprehensive income recorded within ComEd’s Consolidated Balance Sheets as of December 31, 2005 and 2004.

	December 31,
	2005			2004
Accumulated other comprehensive loss
Foreign currency translation adjustment	$	—		$	2
Unrealized loss on marketable securities		(1	)		(2	)
Total accumulated other comprehensive loss	$	(1	)	$	—

305

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

The following table provides additional information about the regulatory assets and liabilities of ComEd as of December 31, 2005 and 2004.

Regulatory assets (liabilities)
Nuclear decommissioning	$	(1,435	)	$	(1,433	)
Removal costs		(1,015	)		(1,011	)
Reacquired debt costs and interest-rate swap settlements		107			118
Conditional asset retirement obligations		91			—
Recoverable transition costs		43			87
Deferred income taxes		8			4
Other		31			31
Total regulatory assets (liabilities)	$	(2,170	)	$	(2,204	)

Nuclear decommissioning. Generation is responsible for decommissioning the nuclear plants formerly owned by ComEd. These amounts represent future nuclear decommissioning costs that exceed (regulatory asset) or are less than (regulatory liability) the associated decommissioning trust fund assets. Generation and ComEd believe the trust fund assets, including prospective earnings thereon and any future collections from customers, will equal the associated future decommissioning costs at the time of decommissioning. See Note 11—Nuclear Decommissioning for additional information.

Removal costs. These amounts represent funds received from customers to cover the future removal of property, plant and equipment. See Note 5—Property, Plant and Equipment for further information.

Reacquired debt costs and interest-rate swap settlements. The reacquired debt 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. Interest-rate swap settlements are deferred and amortized over the period that the related debt is outstanding.

Conditional asset retirement obligations. These costs represent future removal costs associated with asset retirement obligations which will be collected over the remaining lives of the underlying assets. See Note 12—Conditional ARO for further information.

Recoverable transition costs. These charges, related to amounts that would have been unrecoverable but for the recovery mechanism, such as the CTC allowed under the Illinois restructuring act, 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. See Note 4—Regulatory Issues for discussion of recoverable transition cost amortization.

Deferred income taxes. These costs represent the difference between the method by which the regulator allows for the recovery of income taxes and how income taxes would be recorded by unregulated entities. 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 rate-making policies of the ICC, as well as the revenue impacts thereon, and assume continued recovery of these costs in future rates. See Note 10—Income Taxes.

306

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Recovery of regulatory assets. The regulatory asset related to deferred income taxes did not require a cash outlay of investor-supplied funds; consequently these costs are not earning a rate of return. The regulatory assets for conditional asset retirement obligations, 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 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 customers.

19. Related Party Transactions

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 46-R. Prior periods were not restated.

ComEd’s financial statements reflect related-party transactions with its unconsolidated affiliates as presented in the tables below:

	For the Years Ended December 31,
	2005			2004			2003
Operating revenues from affiliates
ComEd Transitional Funding Trust	$	3		$	3		$	—
Interest expense to affiliates
ComEd Transitional Funding Trust		66			85			—
ComEd Financing II		13			13			—
ComEd Financing III		13			13			—
Equity in earnings (losses) of unconsolidated affiliates
ComEd Funding LLC		(14	)		(20	)		—
ComEd Financing III		—			1			—

307

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

	December 31,
	2005		2004
Receivables from affiliates (current)
ComEd Transitional Funding Trust	$	14	$	9
Investment in affiliates
ComEd Transitional Funding LLC		18		36
ComEd Financing II		10		10
ComEd Financing III		6		6
Receivable from affiliates (noncurrent)
ComEd Transitional Funding Trust		12		10
Payables to affiliates (current)
ComEd Financing II		6		6
ComEd Financing III		4		4
Long-term debt to ComEd Transitional Funding Trust and other financing trusts (including due within one year)
ComEd Transitional Funding Trust		987		1,341
ComEd Financing II		155		155
ComEd Financing III		206		206

In addition to the transactions described above, ComEd’s financial statements include related-party transactions as reflected in the tables below.

	For the Years Ended December 31,
	2005		2004		2003
Operating revenues from affiliates
Generation(a)	$	8	$	17	$	50
Enterprises(a)		—		1		15
Purchased power from affiliate
PPA with Generation(b)		3,174		2,374		2,479
Operations & maintenance from (to) affiliates
BSC(c)		193		192		102
Enterprises(d, e)		—		—		26
PECO(f)		—		—		(5	)
Interest income from affiliates
UII(g)		—		16		21
Exelon intercompany money pool(h)		3		3		2
Other		1		1		2
Capitalized costs
BSC(c)		62		62		18
Enterprises(e)		—		—		21
Cash dividends paid to parent		498		457		401

308

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

	December 31,
	2005		2004
Receivables from affiliates (current)
Other	$	23	$	1
Contributions to Exelon intercompany money pool(h)		—		308
Receivables from affiliates (noncurrent)
Generation(i)		1,435		1,433
Exelon Enterprises(j)		—		—
Payables to affiliates (current)
Generation decommissioning(k)		11		11
Generation(a, b)		242		189
BSC(c)		14		17
Borrowings from Exelon’s intercompany money pool(h)		140		—
Payables to affiliates (noncurrent)
Generation decommissioning(k)		—		11
Other		—		6
Shareholders’ equity—receivable from parent(l)		—		125

(a) ComEd provides retail electric and ancillary services to Generation. ComEd provided electric and ancillary services to certain Enterprises companies which were sold in 2004. Prior to joining PJM on May 1, 2004, ComEd also provided transmission services to Generation and Enterprises.

(b) ComEd has entered into a full-requirements purchase power agreement (PPA), as amended, with Generation. See Note 20—Commitments and Contingencies for more information regarding the PPA.

(c) ComEd receives a variety of corporate support services from Exelon Business Services Company (BSC), including legal, human resources, financial, information technology, supply management services, planning and engineering of delivery systems, management of construction, maintenance and operations of the transmission and delivery systems and management of other support services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(d) ComEd had contracted with a subsidiary of Exelon Services (an Enterprises company) to provide energy conservation services to ComEd customers. The subsidiary was sold by Exelon in 2004.

(e) 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.

(f) In 2003, ComEd provided hurricane restoration assistance to PECO during Hurricane Isabel.

(g) ComEd had a note and interest receivable with a variable rate of the one month forward LIBOR rate plus 50 basis points from UII, LLC (successor to Unicom Investments Inc.) relating to ComEd’s December 1999 fossil plant sale. The note was paid in full during 2004.

(h) ComEd participates in Exelon’s intercompany money pool. ComEd earns interest on its contributions to the money pool and pays interest on its borrowings from the money pool at a market rate of interest.

(i) ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd’s customers. See Note 13—Nuclear Decommissioning for additional information.

(j) As of December 31, 2004, ComEd had an outstanding note receivable from Exelon Enterprises in the amount of $22 million. The note matures on December 31, 2008. As of December 31, 2004, ComEd also had a note payable to Exelon Enterprises in the amount of $22 million. Both of these amounts were repaid during 2005.

(k) 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 its customers to Generation.

(l) ComEd had a non-interest bearing receivable from Exelon related to a corporate restructuring in 2001. The receivable was settled in 2005.

309

Commonwealth Edison Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

20. 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 (Loss)					Income (Loss) Before Cumulative Effect Of a Change in Accounting Principle					Net Income (Loss)
	2005		2004		2005			2004		2005			2004		2005			2004
Quarter ended:
March 31	$	1,386	$	1,336	$	188		$	407	$	70		$	184	$	70		$	184
June 30		1,488		1,403		254			431		109			204		109			204
September 30		1,948		1,720		463			410		224			124		224			124
December 31(a)		1,442		1,344		(917	)		369		(1,079	)		164		(1,088	)		164

(a) Results of operations for the quarter ended December 31, 2005 included a $1.2 billion impairment of goodwill.

310

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

PECO

Executive Overview

A discussion of items pertinent to PECO’s executive overview is set forth under “EXELON CORPORATION—Executive Overview” of this Report.

Results of Operations

Year Ended December 31, 2005 Compared To Year Ended December 31, 2004

A discussion of PECO’s results of operations for 2005 compared to 2004 is set forth under “Results of Operations—PECO” in “EXELON CORPORATION—Results of Operations” of this Report.

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

A discussion of PECO’s results of operations for 2004 compared to 2003 is set forth under “Results of Operations—PECO” in “EXELON CORPORATION—Results of Operations” of this Report.

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 the capital markets at reasonable terms, PECO has access to a revolving credit facility that PECO currently utilizes to support its commercial paper program. See the “Credit Matters” section of “Liquidity and Capital Resources” for further discussion.

Capital resources are used primarily to fund PECO’s capital requirements, including construction, retirement of debt, the payment of dividends and contributions to Exelon’s pension plans.

Cash Flows from Operating Activities

A discussion of items pertinent to PECO’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

Cash Flows from Investing Activities

A discussion of items pertinent to PECO’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

Cash Flows from Financing Activities

A discussion of items pertinent to PECO’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

311

Credit Matters

A discussion of credit matters pertinent to PECO is set forth under “Credit Matters” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations

A discussion of PECO’s contractual obligations, commercial commitments and off-balance sheet obligations is set forth under “Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

Critical Accounting Policies and Estimates

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

New Accounting Pronouncements

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK—PECO

PECO is exposed to market risks associated with credit and interest rates. These risks are described above under “Quantitative and Qualitative Disclosures about Market Risk—Exelon.”

312

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PECO

Report of Independent Registered Public Accounting Firm

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 its subsidiaries (PECO) at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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 the financial statement schedule are the responsibility of PECO’s management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 variable interest entities in 2003; and its method of accounting for conditional asset retirement obligations as of December 31, 2005.

PricewaterhouseCoopers LLP

Chicago, Illinois

February 15, 2006

313

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Income

	For the Years Ended December 31,
(in millions)	2005			2004			2003
Operating revenues
Operating revenues	$	4,893		$	4,468		$	4,377
Operating revenues from affiliates		17			19			11
Total operating revenues		4,910			4,487			4,388
Operating expenses
Purchased power		248			197			244
Purchased power from affiliate		1,670			1,447			1,433
Fuel		596			511			419
Fuel from affiliate		1			17			—
Operating and maintenance		440			440			519
Operating and maintenance from affiliates		109			107			57
Depreciation and amortization		566			518			487
Taxes other than income		231			236			173
Total operating expenses		3,861			3,473			3,332
Operating income		1,049			1,014			1,056
Other income and deductions
Interest expense		(56	)		(56	)		(321	)
Interest expense to affiliates		(224	)		(247	)		(3	)
Distributions on mandatorily redeemable preferred securities		—			—			(8	)
Equity in losses of unconsolidated affiliates		(16	)		(25	)		—
Interest income from affiliates		1			—			—
Other, net		13			18			2
Total other income and deductions		(282	)		(310	)		(330	)
Income before income taxes and cumulative effect of a change in accounting principle		767			704			726
Income taxes		247			249			253
Net income before cumulative effect of a change in accounting principle		520			455			473
Cumulative effect of a change in accounting principle (net of income taxes of ($2))		(3	)		—			—
Net income		517			455			473
Preferred stock dividends		4			3			5
Net income on common stock	$	513		$	452		$	468

See Notes to Consolidated Financial Statements

314

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Cash Flows

	For the Years Ended December 31,
(in millions)	2005			2004			2003
Cash flows from operating activities
Net income	$	517		$	455		$	473
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization		566			518			487
Cumulative effect of a change in accounting principle (net of income taxes)		3			—			—
Provision for uncollectible accounts		45			47			52
Deferred income taxes and amortization of investment tax credits		(82	)		(98	)		(50	)
Equity in losses of unconsolidated affiliates		16			25			—
Other non-cash operating activities		4			9			8
Changes in assets and liabilities:
Accounts receivable		(118	)		(59	)		(24	)
Inventories		(35	)		(21	)		(32	)
Deferred energy costs		(14	)		19			(42	)
Other current assets		(4	)		(1	)		(2	)
Accounts payable, accrued expenses and other current liabilities		13			18			(67	)
Change in receivables and payables to affiliates, net		31			(4	)		(31	)
Income taxes		(99	)		57			21
Pension asset and non-pension postretirement benefits obligation		(159	)		23			9
Other noncurrent assets and liabilities		20			(5	)		12
Net cash flows provided by operating activities		704			983			814
Cash flows from investing activities
Capital expenditures		(298	)		(225	)		(250	)
Changes in Exelon intercompany money pool contributions		26			(34	)		—
Change in restricted cash		27			(3	)		(9	)
Other investing activities		4			11			4
Net cash flows used in investing activities		(241	)		(251	)		(255	)
Cash flows from financing activities
Issuance of long-term debt		—			75			450
Retirement of long-term debt		(16	)		(235	)		(718	)
Issuance of long-term debt to financing trusts		—			—			103
Retirement of long-term debt to financing trusts		(481	)		(393	)		—
Change in short-term debt		220			(46	)		(154	)
Retirement of mandatorily redeemable preferred stock		—			—			(50	)
Retirement of preferred stock		—			—			(50	)
Dividends paid on common and preferred stock		(473	)		(394	)		(327	)
Contribution from parent		250			312			159
Other financing activities		—			5			—
Net cash flows used in financing activities		(500	)		(676	)		(587	)
Increase (decrease) in cash and cash equivalents		(37	)		56			(28	)
Cash and cash equivalents at beginning of period		74			18			46
Cash and cash equivalents at end of period	$	37		$	74		$	18

See Notes to Consolidated Financial Statements

315

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Consolidated Balance Sheets

	December 31,
(in millions)	2005			2004
Assets
Current assets
Cash and cash equivalents	$	37		$	74
Restricted cash		2			29
Accounts receivable, net
Customer		454			368
Other		57			34
Affiliate		13			—
Inventories, at average cost
Gas		151			117
Materials and supplies		11			10
Contributions to Exelon intercompany money pool		8			34
Deferred income taxes		7			24
Deferred energy costs		39			25
Other		16			12
Total current assets		795			727
Property, plant and equipment, net		4,471			4,329
Deferred debits and other assets
Regulatory assets		4,386			4,790
Investments		22			22
Investment in affiliates		73			87
Receivable from affiliate		68			46
Prepaid pension asset		195			77
Other		8			9
Total deferred debits and other assets		4,752			5,031
Total assets	$	10,018		$	10,087
Liabilities and shareholders’ equity
Current liabilities
Commercial paper	$	220		$	—
Long-term debt due within one year		—			46
Long-term debt to PECO Energy Transition Trust due within one year		199			165
Accounts payable		182			121
Accrued expenses		92			217
Payables to affiliates		178			146
Customer deposits		54			42
Other		11			11
Total current liabilities		936			748
Long-term debt		1,183			1,153
Long-term debt to PECO Energy Transition Trust		2,776			3,291
Long-term debt to other financing trusts		184			184
Deferred credits and other liabilities
Deferred income taxes		2,781			2,834
Unamortized investment tax credits		17			19
Asset retirement obligations		20			—
Non-pension postretirement benefits obligation		278			319
Other		139			141
Total deferred credits and other liabilities		3,235			3,313
Total liabilities		8,314			8,689
Commitments and contingencies
Shareholders’ equity
Common stock		2,193			2,176
Preferred stock		87			87
Receivable from parent		(1,232	)		(1,482	)
Retained earnings		649			607
Accumulated other comprehensive income		7			10
Total shareholders’ equity		1,704			1,398
Total liabilities and shareholders’ equity	$	10,018		$	10,087

See Notes to Consolidated Financial Statements

316

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, 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
Net income		—			—			—			455			—			455
Common stock dividends		—			—			—			(391	)		—			(391	)
Preferred stock dividends		—			—			—			(3	)		—			(3	)
Repayment of receivable from parent		—			—			141			—			—			141
Capital contribution from parent		156			—			—			—			—			156
Allocation of tax benefit from parent		21			—			—			—			—			21
Other comprehensive income, net of income taxes of $(2)		—			—			—			—			3			3
Balance, December 31, 2004		2,176			87			(1,482	)		607			10			1,398
Net income		—			—			—			517			—			517
Common stock dividends		—			—			—			(469	)		—			(469	)
Preferred stock dividends		—			—			—			(4	)		—			(4	)
Repayment of receivable from parent		—			—			250			—			—			250
Allocation of tax benefit from parent		15			—			—			—			—			15
Other comprehensive loss, net of income taxes of $(3)		—			—			—			—			(3	)		(3	)
Other		2			—			—			(2	)		—			—
Balance, December 31, 2005	$	2,193		$	87		$	(1,232	)	$	649		$	7		$	1,704

See Notes to Consolidated Financial Statements

317

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Comprehensive Income

	For the Years Ended December 31,
(in millions)	2005			2004		2003
Net income	$	517		$	455	$	473
Other comprehensive income (loss)
Change in net unrealized gain (loss) on cash-flow hedges, net of income taxes of $(3), $(1) and $0, respectively		(3	)		1		—
Unrealized gain on marketable securities, net of income taxes of $0, $(1) and $1, respectively		—			2		2
Total other comprehensive income (loss)		(3	)		3		2
Total comprehensive income	$	514		$	458	$	475

See Notes to Consolidated Financial Statements

318

PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements

(Dollars in millions unless otherwise noted)

1. Significant Accounting Policies

Description of Business

Incorporated in Pennsylvania in 1929, PECO Energy Company (PECO) is a regulated utility engaged principally in the purchase, transmission, distribution and sale of electricity to residential, commercial and industrial customers in southeastern Pennsylvania, including the City of Philadelphia, and the distribution and sale of natural gas to residential, commercial and industrial customers in the Pennsylvania counties surrounding the City of Philadelphia. 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 energy service to customers who do not choose an alternate electric generation supplier.

Basis of Presentation

PECO, a regulated electric and gas utility, is a principal subsidiary of Exelon Corporation (Exelon), which owns 100% of PECO’s common stock.

PECO’s consolidated financial statements include the accounts of its subsidiaries, including ExTel Corporation, LLC, Adwin Realty Company and PECO Wireless, LP, except certain financing trusts as described below. All intercompany transactions have been eliminated.

As of July 1, 2003, PECO Energy Capital Trust IV (PECO Trust IV) is no longer consolidated within the financial statements of PECO. Effective December 31, 2003, the accounts of PECO Energy Transition Trust (PETT) and PECO Energy Capital Corporation (PECC) are no longer consolidated. PECC is the sole general partner of PECO Energy Capital L.P. (PEC L.P.), which is the sponsor of PECO Energy Capital Trust III (PECO Trust III). PETT is a separate legal entity from PECO; the debt issued by PETT is solely its obligation, and its assets are not available to creditors of PECO. See “Variable Interest Entities” below for further discussion of the adoption of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46 (revised December 2003) “Consolidation of Variable Interest Entities” (FIN 46-R) and the resulting deconsolidation of these financing trusts. PECO accounts for its less than 20% owned investments under the cost method of accounting.

Reclassifications

Certain prior year amounts have been reclassified in the financial statements for comparative purposes. The reclassifications did not affect net income.

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 asset retirement obligations, inventory reserves,

319

PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

allowance for doubtful accounts, asset impairments, pension and other postretirement benefits, derivative instruments, fixed asset depreciation, environmental costs, taxes, severance and unbilled energy revenues.

Accounting for the Effects of Regulation

PECO accounts for its operations in accordance with accounting policies prescribed by the regulatory authorities having jurisdiction, principally the Pennsylvania Public Utility Commission (PAPUC) under state public utility laws, the Federal Energy Regulatory Commission (FERC) under various Federal laws and the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA) prior to its repeal effective February 8, 2006. PECO applies Statement of Financial Accounting Standard (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” (SFAS No. 71). SFAS No. 71 requires PECO to record in its financial statements the effects of rate regulation for 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. PECO believes that it is probable that its currently recorded regulatory assets and liabilities will be recovered in future rates. However, PECO continues to evaluate its ability to apply SFAS No. 71. If a separable portion of PECO’s business were no longer to meet the provisions of SFAS No. 71, PECO would be required to eliminate from its financial statements the effects of regulation for that portion, which could have a material impact on its financial condition and results of operations. See Note 2—Regulatory Issues for further information regarding the repeal of PUCHA effective February 8, 2006.

Segment Information

PECO operates in one business segment.

Variable Interest Entities

FIN 46 and its revision FIN 46-R addressed the requirements for consolidating certain variable interest entities. FIN 46 was effective for PECO’s variable interest entities created after January 31, 2003. FIN 46-R was effective December 31, 2003 for PECO’s variable interest entities that were considered to be special-purpose entities and as of March 31, 2004 for all other variable interest entities.

PECO Trust IV, a financing subsidiary of PECO created in May 2003, was deconsolidated from the financial statements of PECO pursuant to the provisions of FIN 46 as of July 1, 2003. Pursuant to the provisions of FIN 46-R, as of December 31, 2003 the remaining financing trusts of PECO, namely PECO Trust III (formed in April 1998) and PETT (formed in June 1998), were deconsolidated from PECO’s financial statements. Amounts owed to these financing trusts at December 31, 2005 and 2004 of $3.2 billion and $3.6 billion, respectively, were recorded as debt to financing trusts within PECO’s Consolidated Balance Sheets.

This change in presentation related to the financing trusts had no effect on PECO’s net income. In accordance with FIN 46-R, prior periods were not restated. The maximum exposure to loss as a result of PECO’s involvement with the financing trusts was $73 million and $87 million at December 31, 2005 and 2004, respectively.

Revenues

Operating revenues are 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 customers (see Note 3—Accounts Receivable).

320

PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

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 benefits carried forward. 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.

Pursuant to the Internal Revenue Code, Exelon and its subsidiaries file a consolidated Federal income tax return that includes its subsidiaries in which it owns at least 80% of the outstanding stock. Income taxes are allocated to each of Exelon’s subsidiaries included in the filing of the consolidated Federal income tax return based on the separate return method. PECO records an income tax valuation allowance for deferred tax assets which are not more likely than not to be realized in the future (see Note 8—Income Taxes).

PECO is a party to an agreement (Tax Sharing Agreement) with Exelon 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.

Losses on Reacquired Debt

Recoverable 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 rate-making purposes. Losses on other reacquired debt are recognized in PECO’s Consolidated Statements of Income as incurred.

Comprehensive Income

Comprehensive income includes all changes in equity during a period except those resulting from investments by and distributions to shareholders. Other comprehensive income primarily relates to unrealized gains and losses on cash-flow hedge instruments. Comprehensive income is reflected in PECO’s Consolidated Statements of Changes in Shareholders’ Equity and PECO’s Consolidated Statements of Comprehensive Income.

Cash and Cash Equivalents

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

Restricted Cash

As of December 31, 2005, restricted cash primarily represented funds from the sales of assets that were subject to PECO’s Mortgage Indenture. Restricted cash is not available for general operations until released from the Mortgage Indenture.

Allowance for Doubtful Accounts

The allowance for doubtful accounts reflects PECO’s best estimate of probable losses in the accounts receivable balances. The allowance is based on known troubled accounts, historical

321

PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

experience and other currently available evidence. Customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, typically monthly. Customer accounts are written off based upon approved regulatory requirements.

Inventories

Inventories are recorded at the lower of cost or market, and provisions are made for excess and obsolete inventory.

Gas.Gas inventory includes the weighted average costs of stored natural gas and propane. The costs of natural gas and propane are generally included in inventory when purchased and charged to fuel expense or deferred energy costs when used. PECO has several long-term storage contracts for natural gas as well as a liquefied natural gas storage facility.

Materials and Supplies. Materials and supplies inventory generally includes the average costs of transmission and distribution materials. Materials are generally charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.

Marketable Securities

Marketable securities are classified as available-for-sale securities and are reported at fair value pursuant to SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” with the unrealized gains and losses, net of tax, reported in other comprehensive income. At December 31, 2005 and 2004, PECO had no held-to-maturity 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. At December 31, 2005 and 2004, deferred energy costs of $39 million and $25 million, respectively, were recorded as current assets on PECO’s Consolidated Balance Sheets.

Leases

PECO accounts for leases in accordance with SFAS No. 13, “Accounting for Leases” and determines whether its long-term purchase power and sales contracts are leases pursuant to EITF Issue No. 01-8, “Determining Whether an Arrangement is a Lease.” At the inception of the lease, or subsequent modification, PECO determines whether the lease is an operating or capital lease based upon its terms and characteristics.

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.

Upon retirement, the cost of regulated property, net of salvage, is charged to accumulated depreciation in accordance with the composite method of depreciation. Removal costs are capitalized

322

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

when incurred and depreciated over the life of the new asset constructed consistent with PECO’s regulatory recovery mechanism. For unregulated property, the cost and accumulated depreciation of property, plant and equipment retired or otherwise disposed of are removed from the related accounts.

See Note 4—Property, Plant and Equipment and Note 16—Supplemental Financial Information for additional information regarding 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, 2005 and 2004, net unamortized capitalized software costs totaled $30 million and $46 million, respectively. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed ten years. Capitalized software costs are being amortized over five to ten years pursuant to regulatory approval. During 2005, 2004 and 2003, PECO amortized capitalized software costs of $23 million, $12 million and $15 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, presented by average service life and as a percentage of average service life for each asset category, are presented in the tables below. See Note 4—Property, Plant and Equipment for information regarding a change in PECO’s depreciation rates.

Average Service Life in Years by Asset Category	2005	2004	2003
Electric—transmission and distribution	5-65	5-65	8-65
Gas	5-85	5-85	8-85
Common—electric and gas	5-46	5-46	6-46
Average Service Life Percentage by Asset Category	2005	2004	2003
Electric—transmission and distribution	2.11%	2.14%	2.08%
Gas	2.32%	2.52%	2.38%
Common—electric and gas	8.06%	4.60%	7.53%

Amortization of regulatory assets is provided over the recovery period specified in the related legislation or regulatory agreement. See Note 16—Supplemental Financial Information for further information regarding PECO’s regulatory assets.

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 is recorded as a charge to construction work in progress and as a non-cash credit to AFUDC that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities (see Note 16—Supplemental Financial Information). PECO recorded credits to AFUDC of $3 million, $2 million and $1 million in 2005, 2004 and 2003, respectively.

323

PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Derivative Financial Instruments

PECO enters into derivatives to manage exposure to fluctuations in interest rates, changes in interest rates related to planned future debt issuances and changes in the fair value of outstanding debt. PECO’s derivative activities are in accordance with Exelon’s Risk Management Policy (RMP).

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 or normal sales exception. Derivatives on the balance sheet are presented as current or noncurrent mark-to-market derivative assets or liabilities. Changes in the fair value of derivatives are recognized in earnings unless specific hedge accounting criteria are met, in which case those changes are recorded in earnings as an offset to the changes in fair value of the exposure being hedged or deferred in accumulated other comprehensive income and recognized in earnings as hedged transactions occur. Amounts recorded in earnings are included in other, net within PECO’s consolidated statements of 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, and is designated and qualifies as, a fair-value hedge, are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. Changes in the fair value of a derivative that is highly effective, and is designated and qualifies as, a cash-flow hedge are deferred in accumulated other comprehensive income and are recognized in earnings as the hedged transactions occur. Any ineffectiveness is recognized in earnings immediately. On an ongoing basis, PECO assesses the hedge effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that the derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively.

Severance Benefits

PECO participates in Exelon’s ongoing severance plans, which are accounted for 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” (SFAS No. 88). Amounts associated with severance benefits that are considered probable and can be reasonably estimated are accrued. See Note 5—Severance Accounting for further discussion of PECO’s accounting for severance benefits.

Retirement Benefits

PECO participates in Exelon’s defined benefit pension plans and postretirement welfare benefit plans. Exelon’s defined benefit pension plans and postretirement welfare benefit plans are accounted for in accordance with SFAS No. 87, “Employer’s Accounting for Pensions” (SFAS No. 87), SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” (SFAS No. 106) and FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the

324

PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2), and are disclosed in accordance with SFAS No. 132-R, “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an Amendment of FASB Statements No. 87, 88, and 106” (revised 2003) (SFAS No. 132-R). See Note 11—Retirement Benefits for further discussion of PECO’s accounting for retirement benefits.

FSP FAS 106-2.Through Exelon’s postretirement benefit plans, PECO provides retirees with prescription drug coverage. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Prescription Drug Act) was enacted on December 8, 2003. 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. Management believes the prescription drug benefit provided under Exelon’s postretirement benefit plans is at least actuarially equivalent to the Medicare prescription drug benefit. In response to the enactment of the Prescription Drug Act, in May 2004, the FASB issued FSP FAS 106-2, which provided transition guidance for accounting for the effects of the Prescription Drug Act and superseded FSP FAS 106-1, which had been issued in January 2004. FSP FAS 106-1 permitted 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. PECO made the one-time election allowed by FSP FAS 106-1 during the first quarter of 2004. During the second quarter of 2004, PECO early adopted the provisions of FSP FAS 106-2, resulting in a reduction in net periodic post retirement benefit cost.

New Accounting Pronouncements

SFAS No. 151. In November 2004, the FASB issued FASB Statement No. 151, “Inventory Costs—an amendment of ARB No. 43, Chapter 4” (SFAS No. 151), which is the result of its efforts to converge U.S. accounting standards for inventories with International Accounting Standards. SFAS No. 151 requires abnormal amounts of idle facility expense, freight, handling costs and wasted material or spoilage to be recognized as current-period charges. It also requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS No. 151 will be effective for inventory costs incurred beginning January 1, 2006. The adoption of this standard is not expected to have a material impact on PECO.

SFAS No. 123-R.In December 2004, the FASB issued FASB Statement No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123-R). SFAS No. 123-R replaces SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123) and supersedes Accounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees” (APB No. 25). SFAS No. 123-R requires that compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. Exelon will no longer be permitted to follow the intrinsic value accounting method of APB No. 25. APB No. 25 resulted in no expense being recorded for stock option grants for which the strike price was equal to the fair value of the underlying stock on the date of grant, which has been the situation for Exelon for all years prior to 2006. SFAS No. 123-R will be effective for Exelon in the first quarter of 2006 and will apply to all of Exelon’s outstanding unvested share-based payment awards as of January 1, 2006 and all prospective awards using the modified prospective transition method without restatement of prior periods. Exelon will charge a portion of the resulting expense to PECO.

In March 2005, the SEC issued Staff Accounting Bulletin (SAB) No. 107 which expressed the views of the SEC regarding the interaction between SFAS No. 123-R and certain SEC rules and

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(Dollars in millions unless otherwise noted)

regulations. SAB No. 107 provides guidance related to the valuation of share-based payment arrangements for public companies, including assumptions such as expected volatility and expected term.

PECO participates in Exelon’s stock-based compensation plans. Exelon currently accounts for its stock-based compensation plans under the intrinsic method prescribed by APB No. 25 and related interpretations and follows the disclosure requirements of SFAS No. 123 and SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123.” Accordingly, compensation expense related to stock options recognized within the Consolidated Statements of Income was insignificant in 2005, 2004 and 2003. The table below shows the effect on PECO’s net income for 2005, 2004 and 2003 had Exelon elected to account for its stock-based compensation plans using the fair-value method under SFAS No. 123:

	2005		2004		2003
Net income—as reported	$	517	$	455	$	473
Deduct: Total stock-based compensation expense under fair-value method for all awards, net of income taxes(a)		2		3		3
Pro forma net income	$	515	$	452	$	470

(a) The fair value of options granted was estimated using a Black-Scholes-Merton option pricing model.

SFAS No. 153. In December 2004, the FASB issued FASB Statement No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, ‘Accounting for Nonmonetary Transactions’” (SFAS No. 153). Previously, APB Opinion No. 29 had required that the accounting for an exchange of a productive asset for a similar productive asset or an equivalent interest in the same or similar productive asset should be based on the recorded amount of the asset relinquished. The amendments made by SFAS No. 153 are based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, the amendments eliminate the narrow exception for nonmonetary exchanges of similar productive assets and replace it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance, in essence increasing the number of exchanges that will be fair valued in the future. SFAS No. 153 was effective in the third quarter of 2005. The provisions of SFAS No. 153 are applied prospectively. The adoption of this standard did not have a material impact on PECO’s financial condition or results of operations in the third or fourth quarter of 2005.

FIN 47.In March 2005, the FASB issued FIN 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47) which clarifies that the term “conditional asset retirement obligation” as used in FASB Statement No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143), refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 was effective for PECO as of December 31, 2005. See Note 10—Conditional ARO for further information about the impacts of adopting FIN 47.

SFAS No. 154.In May 2005, the FASB issued FASB Statement No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS No. 154). Previously, APB No. 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements” required the inclusion of the cumulative effect of changes in

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(Dollars in millions unless otherwise noted)

accounting principle in net income of the period of the change. SFAS No. 154 requires companies to recognize a change in accounting principle, including a change required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements. PECO will assess the impact of a retrospective application of a change in accounting principle in accordance with SFAS No. 154 when such a change arises after the effective date of January 1, 2006.

Cumulative Effect of Changes in Accounting Principles

FIN 47. During 2005, PECO recorded a charge of $3 million (net of income taxes of $2 million) as a cumulative effect of a change in accounting principle pursuant to the adoption of FIN 47. The impact on PECO’s net income for 2005, 2004 and 2003, adjusted as if FIN 47 had been applied effective during the entirety of those years would have been less than $1 million annually. See discussion of the adoption of FIN 47 above.

2. Regulatory Issues

Through and Out Rates / SECA.In November 2004, the FERC issued two orders authorizing PECO to recover amounts for a limited time during a specified transitional period as a result of the elimination of through and out (T&O) rates for transmission service scheduled out of, or across, its transmission system and ending within pre-expansion PJM Interconnection, LLC (PJM) or Midwest Independent System Operators (MISO) territories. T&O rates were terminated pursuant to FERC orders, effective December 1, 2004. The new rates, known as Seams Elimination Charge/Cost Adjustment/Assignment (SECA), are collected from load-serving entities within PJM and MISO over a transitional period from December 1, 2004 through March 31, 2006, subject to refund, surcharge and hearing. As a load-serving entity, PECO is also required to pay SECA rates during the transitional period based on the benefit it receives from the elimination of T&O rates of other transmission owners within PJM and MISO.

During 2004, prior to the termination of T&O rates, PECO had net T&O collections of approximately $3 million. As a result of the November 2004 FERC orders and potential appeals, PECO may become a net payer of SECA charges. Since the inception of the SECA rates in December 2004, PECO has recorded approximately $7 million of SECA charges net of SECA collections, including $6 million in 2005. Management of PECO believes that appropriate reserves have been established in the event that such SECA collections are required to be refunded. However, as the above amounts collected under the SECA rates are subject to refund and surcharge and the ultimate outcome of the proceeding establishing SECA rates is uncertain, the result of this proceeding may have an effect on PECO’s financial condition, results of operations and cash flows.

Customer Choice.All PECO customers may choose to purchase energy from an alternative electric supplier. As of December 31, 2005, approximately 44,500 customers, representing approximately 5% of PECO’s annual kilowatthour sales, had elected to purchase their electric energy from an alternative electric supplier. Customers who receive energy from an alternative electric supplier continue to pay delivery charges and competitive transition charges (CTCs).

Rate limitations.Pursuant to a settlement agreement related to the merger of Exelon, Unicom Corporation and PECO on October 20, 2000 (PECO / Unicom Merger) with the PAPUC, PECO was subject to agreed-upon electric service rate reductions of $200 million, in aggregate, for the period

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(Dollars in millions unless otherwise noted)

January 1, 2002 through December 31, 2005. As required by the 1998 electric restructuring settlement and as modified by the PECO / Unicom Merger-related settlement agreement, PECO is subject to rate 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.

Partial Settlement before the PAPUC.On January 27, 2006, the PAPUC approved the Merger and a partial settlement regarding PECO’s distribution and transmission rates through 2010 and other financial commitments of PECO related to the Merger. The settlement reflected the conclusion of a process involving the majority of PECO customer groups during which PECO’s cost data, return on equity and estimated Merger synergies were reviewed. The provisions of the PAPUC order and partial settlement are contingent upon the completion of the Merger. The PAPUC order and partial settlement require PECO to implement rate reductions aggregating $120 million during a four-year period and to cap its rates through the end of 2010. During the rate cap period, the PAPUC retains the right to lower PECO’s rates if they are found to be excessive, and PECO retains the right to seek rate increases if certain events (such as 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) occur. The partial settlement also provides substantial funding for alternative energy and environmental projects, economic development, and expanded outreach and assistance for low-income customers. PECO also made commitments for enhanced customer service and reliability, commitments for charitable giving and employment, and a pledge to maintain its Philadelphia headquarters for a period of time. The total of these funding commitments is approximately $44 million, of which $30 million will be expensed at the time the Merger is completed. By separate motion, the PAPUC also indicated its intent to initiate a separate investigation, to which PECO had agreed in the partial settlement, to examine issues related to a potential combination of Philadelphia Gas Works, which provides gas distribution service in the City of Philadelphia, into Exelon’s gas distribution businesses. This investigation will commence no earlier than 30 days after the close of the Merger. The outcome of this potential examination is uncertain. However, Exelon does not believe that the PAPUC has the authority to compel such a transaction if the two parties do not agree to terms through arms length negotiations.

Nuclear Decommissioning Costs.Effective January 1, 2004, the PAPUC approved an adjustment to PECO’s nuclear decommissioning cost adjustment clause permitting PECO to recover an additional $3.6 million annually, or $33 million compared to $29 million previously. The amounts collected by PECO from retail customers are remitted to Generation. See Note 9—Nuclear Decommissioning.

The Energy Policy Act of 2005. The Energy Policy Act of 2005 (the Energy Policy Act), which was signed into law on August 8, 2005, implements several significant changes intended to improve electric reliability, promote investment in electric facilities, streamline electric regulation, improve wholesale competition, address problems identified in the Western energy crisis and Enron collapse, promote fuel diversity and cleaner fuel sources, and promote greater efficiency in electric generation, delivery and use.

The Energy Policy Act also transfers to FERC certain additional authority. FERC obtains new authority to review the acquisition or merger of generating facilities, along with the responsibility to address more explicitly cross-subsidization issues in these situations. FERC now has the authority to approve siting of electric transmission facilities located in national interest electric transmission

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

corridors if states cannot or will not act in a timely manner to approve siting. The Energy Policy Act also creates a self-regulating electric reliability organization with FERC oversight to enforce reliability rules.

Additionally, the Energy Policy Act repealed PUHCA effective February 8, 2006. Since Exelon was a registered holding company under PUHCA, Exelon and its subsidiaries, including PECO, were subject to a number of restrictions. These restrictions involved financings, investments and affiliate transactions. Exelon had an order under PUHCA authorizing financing transactions within certain limits. Exelon also had an order under PUHCA authorizing development activities, the formation of new intermediate subsidiaries for internal corporate structuring, internal corporate reorganizations, and investments in certain non-U.S. energy-related subsidiaries. PUHCA also limited the businesses in which Exelon could engage in and the investments that Exelon could make, and required that Exelon’s utility subsidiaries constituted a single system that could be operated in an efficient, coordinated manner. With the repeal of PUHCA, Exelon will no longer be subject to these restrictions. However, Section 203 of the Federal Power Act as amended by the Energy Policy Act, and regulations promulgated thereunder, governs intercompany system financings and cash management arrangements, certain internal corporate reorganizations, and certain holding company acquisitions of public utility and holding company securities. FERC obtained additional jurisdiction for the review of affiliate transactions, and FERC’s financing jurisdiction resumes to the extent that it was preempted by PUHCA. With the repeal of PUHCA, the SEC’s financing jurisdiction under PUHCA for PECO’s short-term financings reverted to FERC. On February 3, 2006, PECO received an order from the FERC authorizing short-term financing for an amount not to exceed $1.5 billion, effective February 8, 2006 through December 31, 2007. To the extent that the SEC’s jurisdiction under PUHCA preempted certain aspects of state regulation of Exelon, the repeal of PUHCA will permit the states in which Exelon and its subsidiaries, including PECO, operate to adopt additional regulations if they so choose, absent any preemption by the FERC.

3. Accounts Receivable

Customer accounts receivable at December 31, 2005 and 2004 included estimated unbilled revenues associated with unread meters, representing an estimate for the unbilled amount of energy or services provided to customers, and allowance for uncollectible accounts as follows:

	2005		2004
Unbilled revenues	$	175	$	143
Allowance for uncollectible accounts		39		52

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 through November 2010 based on the November 2005 amendment to this agreement. At December 31, 2005, PECO had sold a $225 million interest in accounts receivable, consisting of a $195 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 $30 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable (see Note 7—Long-Term Debt). At December 31, 2004, PECO had sold a $225 million interest in accounts receivable, consisting of a $179 million interest in accounts receivable which PECO accounted for as a sale under SFAS No. 140 and a $46 million interest in special-agreement accounts receivable which was accounted for as a long-term note payable and reflected on PECO’s consolidated balance sheets

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(Dollars in millions unless otherwise noted)

as long-term debt due within one year. 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, 2005 and 2004, PECO met this requirement and was not required to make any cash deposits.

4. Property, Plant and Equipment

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2005 and 2004:

	December 31,
Asset Category	2005		2004
Electric—transmission and distribution	$	4,577	$	4,501
Gas—transmission and distribution		1,482		1,436
Common		476		501
Construction work in progress		88		37
Asset retirement cost(a)		5		—
Other property, plant and equipment		15		19
Total property, plant and equipment		6,643		6,494
Less accumulated depreciation		2,172		2,165
Property, plant and equipment, net	$	4,471	$	4,329

(a) See Note 10—Conditional ARO for further information.

PECO’s depreciation expense, which is included in cost of service for rate purposes, includes the estimated cost of dismantling and removing plant from service upon retirement. Removal costs are collected after they are incurred consistent with allowed regulatory recovery mechanisms. For more information, see Note 16—Supplemental Financial Information.

PECO has undivided ownership interests in jointly owned electric transmission plant comprised of a 22.00% ownership of 127 miles of 500,000 voltage lines located in Pennsylvania and a 42.55% ownership of 151 miles of 500,000 voltage lines located in Delaware and New Jersey. Gross plant and accumulated depreciation balances for these assets were $61 million and $28 million, respectively, at December 31, 2005 and $61 million and $27 million, respectively, at December 31, 2004. PECO’s undivided ownership interests are financed with PECO funds and all operations are accounted for as if such participating interests were wholly owned facilities. PECO’s share of direct expenses of the jointly owned plant is included in the corresponding operating expenses on the Consolidated Statements of Income.

5. Severance Accounting

PECO provides severance and health and welfare benefits to terminated employees pursuant to pre-existing severance plans maintained by Exelon primarily based upon each individual employee’s years of service and compensation level. PECO accounts for its ongoing severance plans in accordance with SFAS No. 112 and SFAS No. 88 and accrues amounts associated with severance benefits that are considered probable and that can be reasonably estimated.

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PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

The following tables present total salary continuance severance costs, recorded as an operating and maintenance expense, during 2005, 2004 and 2003:

Salary Continuance Severance
Expense recorded—2005	$	1
Expense recorded—2004		3
Expense recorded—2003		16

The following table provides a roll forward of the salary continuance severance obligations from January 1, 2004 through December 31, 2005:

Salary Continuance Obligations
Balance at January 1, 2004	$	14
Severance charges recorded		3
Cash payments		(10	)
Balance at January 1, 2005	$	7
Severance charges recorded		1
Cash payments		(7	)
Balance at December 31, 2005	$	1

6. Short-Term Debt

	2005		2004		2003
Average borrowings	$	30	$	23	$	168
Maximum borrowings outstanding		257		207		582
Average interest rates, computed on a daily basis		3.44%		1.08%		1.23%
Average interest rates, computed at December 31		4.58%		—		1.02%

At December 31, 2003, Exelon, along with ComEd, PECO and Generation, participated with a group of banks in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion unsecured revolving facility maturing on July 16, 2009, and the $750 million three-year facility was reduced to $500 million maturing on October 31, 2006. 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.

At December 31, 2005, PECO had the following sublimits and available capacity under the credit agreements and the indicated amounts of outstanding commercial paper:

Borrower	Bank Sublimit (a)		Available Capacity (b)		Outstanding Commercial Paper
PECO	$	350	$	350	$	220

(a) Sublimits under the credit agreements can change upon written notification to the bank group.

(b) Available capacity represents the bank sublimit net of outstanding letters of credit. The amount of commercial paper outstanding does not reduce the available capacity under the credit facilities.

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PECO Energy Company and Subsidiary Companies

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(Dollars in millions unless otherwise noted)

Interest rates on advances under the credit facilities are based on either prime or the London Interbank Offering Rate (LIBOR) 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 LIBOR adder is 170 basis points.

The credit agreements require PECO to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital and distributions on preferred securities of subsidiaries. For the twelve-month period ended December 31, 2005, PECO’s minimum cash from operations to interest expense ratio was 2.25 to 1. At December 31, 2005, PECO was in compliance with this threshold.

7. Long-Term Debt

	Rates		Maturity Date	December 31,
				2005			2004
Long-term debt
First Mortgage Bonds(a) (b):
Fixed rates	3.50%-5.95	%	2008-2034	$	1,000		$	1,000
Floating rates	2.95%-3.30	%	2012		154			154
Notes payable—accounts receivable agreement	4.23	%	2010		30			46
Total long-term debt(c)					1,184			1,200
Unamortized debt discount and premium, net					(1	)		(1	)
Long-term debt due within one year					—			(46	)
Long-term debt				$	1,183		$	1,153
Long-term debt due to PETT(d) ,(e)
Series 1999-A:
Fixed Rates	6.05%-6.13	%	2006-2008	$	1,419		$	1,890
Floating Rates	—		—		—			10
Series 2000-A	7.63%-7.65	%	2009		750			750
Series 2001	6.52	%	2010		806			806
Long-term debt due to PETT					2,975			3,456
Long-term debt due to PETT within one year					(199	)		(165	)
Total long-term debt due to PETT				$	2,776		$	3,291
Long-term debt to other financing trusts( d,e)
Subordinated debentures to PECO Trust III	7.38	%	2028		81			81
Subordinated debentures to PECO Trust IV	5.75	%	2033		103			103
Total long-term debt to other financing trusts				$	184		$	184

(a) PECO’s utility plant is subject to the lien of its mortgage indenture.

(b) Includes first mortgage bonds issued under the PECO mortgage indenture securing pollution control bonds and notes.

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(Dollars in millions unless otherwise noted)

(c) Long-term debt maturities in the periods 2006 through 2010 and thereafter are as follows:

Year
2006	$	—
2007		—
2008		450
2009		—
2010		30
Thereafter		704
Total	$	1,184

(d) Effective July 1, 2003, PECO Trust IV, a financing subsidiary created in May 2003, was deconsolidated from the financial statements in conjunction with the adoption of FIN 46. Effective December 31, 2003, PECO Trust III, and PETT were deconsolidated from the financial statements in conjunction with the adoption of FIN 46-R. Amounts owed to these financing trusts are recorded as debt to financing trusts within the Consolidated Balance Sheets.

(e) Long-term debt to financing trusts maturities in the periods 2006 through 2010 and thereafter are as follows:

Year
2006	$	199
2007		645
2008		625
2009		700
2010		806
Thereafter		184
Total	$	3,159

Issuances of Long-Term Debt. PECO did not issue any long-term debt during 2005.

Debt Retirements and Redemptions.During 2005, PECO retired $16 million of its Notes payable—accounts receivable agreement. See Note 3—Accounts Receivable for additional information regarding the accounts receivable agreement. During 2005 and 2004, PECO made scheduled payments of $481 million and $393 million, respectively, related to its obligation to PETT.

See Note 12—Fair Value of Financial Assets and Liabilities for additional information regarding interest-rate swaps.

See Note 13—Preferred Securities for additional information regarding preferred stock.

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(Dollars in millions unless otherwise noted)

8. Income Taxes

PECO’s income tax expense (benefit) is comprised of the following components:

	For the Year Ended December 31,
	2005			2004			2003
Included in operations:
Federal
Current	$	312		$	311		$	257
Deferred		(53	)		(59	)		(15	)
Investment tax credit amortization		(2	)		(2	)		(2	)
State
Current		17			36			46
Deferred		(27	)		(37	)		(33	)
Total income tax expense	$	247		$	249		$	253
Included in cumulative effect of a change in accounting principle:
Deferred
Federal	$	(2	)	$	—		$	—
State		—			—			—
Total income tax benefit	$	(2	)	$	—		$	—

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

	For the Year Ended December 31,
	2005		2004		2003
U.S. Federal statutory rate	35.0%		35.0%		35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	(0.9	)	(0.1	)	1.1
Plant basis differences	(1.1	)	0.6		(1.1	)
Amortization of investment tax credit	(0.3	)	(0.4	)	(0.4	)
Other	(0.5	)	0.3		0.2
Effective income tax rate	32.2%		35.4%		34.8%

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PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

The tax effects of temporary differences giving rise to significant portions of PECO’s deferred tax assets and liabilities as of December 31, 2005 and 2004 are presented below:

	2005			2004
Deferred tax liabilities:
Stranded cost recovery	$	(1,465	)	$	(1,632	)
Plant basis difference		(1,363	)		(1,295	)
Deferred debt refinancing costs		(15	)		(17	)
Unrealized gain on derivative financial instruments		(6	)		(9	)
Total deferred tax liabilities		(2,849	)		(2,953	)
Deferred tax assets:
Deferred pension and postretirement obligations		21			51
Other, net		54			92
Total deferred tax assets		75			143
Deferred income tax liabilities (net) on the Consolidated Balance Sheets	$	(2,774	)	$	(2,810	)

In 2005 and 2004, PECO received $15 million and $21 million, respectively from Exelon related to its allocation of tax benefits under the Tax Sharing Agreement.

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 $781 million and $747 million at December 31, 2005 and 2004, respectively. See Note 16—Supplemental Financial Information for further discussion of PECO’s regulatory asset associated with deferred income taxes.

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

9. Nuclear Decommissioning

As a result of corporate restructuring in 2001, assets and liabilities associated with nuclear power plants previously owned by PECO were transferred to Generation. Pursuant to the Nuclear Regulatory Commission (NRC) regulations, Generation has an obligation to decommission these nuclear power plants. Based on the actual or anticipated extended license lives of the nuclear plants, expenditures are expected to begin after 2029 for plants currently in operation. Generation currently recovers costs for decommissioning nuclear generating stations, previously owned by PECO, through regulated rates collected by PECO. The amounts recovered from customers are deposited in trust accounts by Generation and invested for funding of future decommissioning costs of these nuclear generating stations.

PECO currently recovers in revenues funds for decommissioning the former PECO nuclear plants through regulated rates. The amounts recovered from customers are remitted to Generation and deposited into the trust accounts to fund the future decommissioning costs. Under orders from the PAPUC, PECO is permitted to collect from customers up to $33 million annually for the full funding of the expected costs to decommission the former PECO nuclear plants. Based on the provisions of the PAPUC order, the PECO customers are financially responsible for the majority of any shortfalls in the costs to decommission these nuclear units; however, the PECO customers will receive any excess

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

amounts from the trust funds at the completion of decommissioning. Exelon is responsible for 1) the first $50 million of the decommissioning costs above a certain threshold established under the PAPUC order and 2) five percent of the decommissioning costs above that first $50 million of costs that exceed the established threshold. Exelon expects total decommissioning costs to exceed this threshold and expects to be held responsible for the entire $50 million, which is being recognized over the remaining life of the assets. At the end of each financial reporting period, Exelon assesses the amounts currently recorded in trust assets plus future collections less amounts recorded in the asset retirement obligation (ARO) on a plant by plant basis. At December 31, 2005 and 2004, Exelon recorded a regulatory liability for the amount of decommissioning-related assets in excess of the ARO of $68 million and $46 million, respectively.

10. Conditional ARO

As of December 31, 2005, PECO adopted FIN 47, which clarified that a legal obligation associated with the retirement of a long-lived asset whose timing and/or method of settlement are conditional on a future event is within the scope of SFAS No. 143. Under FIN 47, PECO is required to record liabilities associated with its conditional AROs at their estimated fair values if those fair values can be reasonably estimated.

Determination of Conditional AROs

The adoption of FIN 47 required PECO to update an existing inventory, originally created for the adoption of SFAS No. 143, and to determine which, if any, of the conditional AROs could be reasonably estimated. The significant conditional AROs identified by PECO included abatement and disposal of equipment and buildings contaminated with asbestos and Polychlorinated Biphenyls (PCBs).

The ability to reasonably estimate a conditional ARO was a matter of management judgment, based upon management’s ability to estimate a settlement date or range of settlement dates, a method or potential method of settlement and probabilities associated with the potential dates and methods of settlement of its conditional AROs. In determining whether their conditional AROs could be reasonably estimated, management considered PECO’s past practices, industry practices, management’s intent and the estimated economic lives of the assets. The management of PECO concluded that all significant conditional AROs could be reasonably estimated.

PECO was required to measure the conditional AROs at fair value using the methodology prescribed by FIN 47. The transition provisions of FIN 47 required PECO to apply this measurement back to the historical periods in which the conditional AROs were incurred, resulting in a remeasurement of these obligations at the latter of the date that the related assets were placed into service or acquired or the date that the applicable law or environmental regulation became effective. The fair values of the conditional AROs were then estimated using a probability-weighted, discounted cash flow model with multiple scenarios, if applicable. The present value of future estimated cash flows was calculated using credit-adjusted, risk-free rates applicable to PECO in order to determine the fair value of the conditional AROs at the time of adoption of FIN 47.

Conditional AROs of $20 million were recorded as of December 31, 2005 by PECO. Changes in management’s assumptions regarding settlement dates, settlement methods or assigned probabilities could have had a material effect on the liabilities recorded at December 31, 2005 as well as the associated cumulative effect of a change in accounting principle and associated regulatory assets recorded.

336

PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Effect of Adopting FIN 47

FIN 47 required that PECO recognize the following amounts within its financial statements upon the adoption of FIN 47: (i) a liability for any existing conditional AROs adjusted for cumulative accretion to December 31, 2005; (ii) an asset retirement cost (ARC) capitalized as an increase to the carrying amount of the associated long-lived assets; and (iii) cumulative depreciation on the ARC. The transition guidance in FIN 47 required that its adoption be effected through a cumulative change in accounting principle measured as the difference between the amounts recognized in the financial statements prior to the adoption of FIN 47 for conditional AROs and the amounts recognized as of December 31, 2005 pursuant to FIN 47. PECO had not recognized any amounts associated with conditional AROs prior to the adoption of FIN 47.

After considering the transitional guidance included in FIN 47, PECO recorded a charge of $3 million (net of income taxes of $2 million) as a cumulative effect of a change in accounting principle in connection with its adoption. In addition, due to the application of SFAS No. 71, which is further described in Note 1—Significant Accounting Policies, PECO recorded regulatory assets of $13 million associated with the adoption of FIN 47.

The following table presents the line items within PECO’s Consolidated Statements of Income for the year ended December 31, 2005 and the Consolidated Balance Sheets at December 31, 2005 that were affected by the adoption of FIN 47:

Consolidated statements of income line item:
Cumulative effect of a change in accounting principle (net of income taxes of $(2))(a)	$	(3	)
Consolidated balance sheets line items—increase (decrease):
Property, plant and equipment, net(b)		2
Regulatory assets(c)		13
Deferred income taxes (noncurrent liability)		(2	)
Asset retirement obligations(d)		20

(a) Represents the difference between the conditional ARO, net ARC and regulatory assets recorded upon adoption, net of income taxes.

(b) Represents capitalized ARC of $5 million as an increase to the carrying amount of the associated long-lived assets, net of accumulated depreciation of $3 million on the ARC.

(c) Represents an increase to regulatory assets pursuant to SFAS No. 71 for amounts expected to be recovered from customers.

(d) Represents a liability for existing conditional AROs adjusted for cumulative accretion to December 31, 2005.

As noted in Note 1—Significant Accounting Policies, the impact on net income for 2005, 2004 and 2003, adjusted as if FIN 47 had been applied effective during the entirety of those years, would have been less than $1 million annually. The following table presents, on a pro forma basis, what the liability for conditional AROs would have been had FIN 47 been applied during the years 2004 and 2003. These pro forma amounts are estimated based upon the information, assumptions, and interest rates used to measure the liability for conditional AROs recognized upon adoption of FIN 47 as of December 31, 2005.

Pro forma liability for conditional AROs, January 1, 2003	$	17
Pro forma liability for conditional AROs, December 31, 2003		18
Pro forma liability for conditional AROs, December 31, 2004		19

337

PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Prospective Accounting Methodology Under FIN 47

The liabilities associated with conditional AROs will be adjusted on an ongoing basis due to the passage of time, new laws and regulations and revisions to either the timing or amount of the original estimates of undiscounted cash flows. These adjustments could have a significant impact on PECO’s Consolidated Balance Sheets, assuming the provisions of SFAS No. 71 continue to apply.

The liabilities recorded as of December 31, 2005 related to the conditional AROs of PECO will be accreted to their full estimated settlement amounts through the estimated ultimate settlement dates. Most of this accretion charge will be recorded as an increase to PECO’s regulatory assets due to the application of SFAS No. 71.

The net ARC recorded as of December 31, 2005 by PECO will be depreciated over the remaining lives of the related long-lived assets. Most of this charge will be recorded as an increase to PECO’s regulatory assets due to the application of SFAS No. 71.

11. Retirement Benefits

Exelon sponsors defined benefit pension plans and postretirement welfare benefit plans for essentially all PECO employees. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in Exelon-sponsored cash balance pension plans. Substantially all non-union employees hired prior to January 1, 2001 were offered a choice to remain in Exelon’s traditional pension plan or transfer to a cash balance pension plan for management employees. The costs of providing benefits under these plans are dependent on historical information, such as employee age, length of service and level of compensation, and the actual rate of return on plan assets, in addition to 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 prepaid pension asset and non-pension postretirement benefits obligation on PECO’s Consolidated Balance Sheets reflect PECO’s obligations from and to the plan sponsor, Exelon. Employee-related assets and liabilities, including both pension and SFAS No. 106 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.

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

Approximately $30 million, $32 million and $49 million were included in capital and operating and maintenance expense, excluding curtailment and special termination benefit costs, in 2005, 2004 and 2003, respectively, for PECO’s allocated portion of Exelon’s pension and postretirement benefit expense. The 2005 and 2004 amounts each reflect an annualized reduction in net periodic post-retirement benefit cost of $7 million, related to a Federal subsidy provided under the Prescription Drug Act. This subsidy has been accounted for under FSP FAS 106-2, as described in Note 1—Significant Accounting Policies.

338

PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

PECO contributed $189 million, $14 million and $49 million to the Exelon-sponsored plans in 2005, 2004 and 2003, respectively. Of PECO’s total 2005 contributions, $109 million was made in the first quarter and was fully funded by a capital contribution from Exelon. PECO does not expect to contribute to Exelon’s pension benefit plans in 2006.

During 2005, PECO recognized no curtailment charges or special termination benefit costs. During 2004, PECO recognized curtailment charges and special termination benefit costs of $2 million and $2 million (before income taxes), respectively, associated with an overall reduction in participants in Exelon’s pension and postretirement benefit plans due to employee reductions.

PECO participates in a 401(k) savings plan sponsored by Exelon. The plan allows employees to contribute a portion of their pre-tax 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 $6 million, $6 million and $7 million in 2005, 2004 and 2003, respectively.

12. Fair Value of Financial Assets and Liabilities

Non-Derivative Financial Assets and Liabilities

Fair Value.As of December 31, 2005 and 2004, PECO’s carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities are representative of fair value because of the short-term nature of these instruments. Fair values for long-term debt and preferred securities of subsidiaries are determined by an external valuation model which is based on conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves.

The carrying amounts and fair values of PECO’s financial liabilities as of December 31, 2005 and 2004 were as follows:

	2005				2004
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	1,183	$	1,180	$	1,199	$	1,227
Long-term debt to PETT (including amounts due within one year)		2,975		3,129		3,456		3,779
Long-term debt to other financing trusts		184		186		184		193

Credit Risk.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.

Interest-Rate Swaps

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, no net mark-to-market adjustments are expected to occur.

339

PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Cash-Flow Hedges. PECO utilizes interest rate derivatives to lock in interest-rate levels in anticipation of future financings. Forward-starting interest-rate swaps are designated as cash-flow hedges, as defined in SFAS No. 133 and, as such, changes in the fair value of the swaps are recorded in accumulated other comprehensive income (OCI). Any change in the fair value of the hedge as a result of ineffectiveness is recorded immediately in earnings. At December 31, 2005 and 2004, PECO did not have any notional amounts of cash-flow hedges outstanding. However, during 2004, PECO settled interest-rate swaps in the aggregate notional amount of $75 million and recorded a net pre-tax gain of $5 million which was recorded in other comprehensive income, a component of shareholders’ equity, and is being amortized to interest expense over the life of the related debt.

As of December 31, 2005, $5 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 interest payment occurs.

At December 31, 2005 and 2004, the aggregate unamortized net gain on the settlements of swap transactions was $13 million and $21 million, respectively, recorded in accumulated other comprehensive income.

Credit Risk Associated with Derivative Instruments. PECO would be exposed to credit-related losses in the event of non-performance by counterparties that issue derivative instruments. The credit exposure of derivative contracts is represented by the fair value of contracts at the reporting date. The notional amount of derivatives does not represent amounts that are exchanged by the parties and, thus, are not a measure of PECO’s exposure. The amounts exchanged are calculated on the basis of the notional or contract amounts, as well as on the other terms of the derivatives, which relate to interest rates and the volatility of these rates.

13. Preferred Securities

At December 31, 2005 and 2004, cumulative preferred stock of PECO, no par value, consisted of 15,000,000 shares authorized and the outstanding amounts set forth below. Shares of preferred stock have full voting rights, including the right to cumulate votes in the election of directors.

	Current Redemption Price(a)		December 31,
			2005	2004	2005		2004
			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
Total preferred stock			874,720	874,720	$	87	$	87

(a) Redeemable, at the option of PECO, at the indicated dollar amounts per share, plus accrued dividends.

340

PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

14. Common Stock

At December 31, 2005 and 2004, PECO’s common stock without par value consisted of 500,000,000 shares authorized and 170,478,507 shares outstanding.

Undistributed Losses of Equity Method Investments

PECO had undistributed losses of equity method investments of $41 million and $25 million at December 31, 2005 and 2004, respectively.

15. Commitments and Contingencies

Energy Commitments

PECO has entered into a long-term purchase power agreement (PPA) with Generation under which PECO obtains substantially all of its electric supply from Generation through 2010. The price for this electricity is essentially equal to the energy revenues earned from customers as specified by PECO’s 1998 settlement of its restructuring case mandated by the Competition Act. Subsequent to 2010, PECO expects to procure all of its supply from market sources, which could include Generation.

Commercial Commitments

PECO’s commercial commitments as of December 31, 2005, representing commitments potentially triggered by future events, were as follows:

			Expiration within
	Total		2006		2007-2008		2009-2010		2011 and beyond
Letters of credit (non-debt)(a)	$	31	$	31	$	—	$	—	$	—
Surety bonds(b)		34		34		—		—		—
Other		2		2
Total commercial commitments	$	67	$	67	$	—	$	—	$	—

(a) Letters of credit (non-debt)—PECO maintains 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 the 27 sites identified by PECO, the Pennsylvania Department of Environmental Protection has approved the cleanup of nine sites. Of the remaining sites identified by PECO, 11 sites are currently under some degree of active study and/or remediation. In addition, 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.

341

PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

As of December 31, 2005 and December 31, 2004, PECO had accrued the following amounts for environmental liabilities:

	December 31, 2005			December 31, 2004
Total environmental investigation and remediation reserve	$	47		$	47
Portion of total related to MGP investigation and remediation		41	(a)		41	(b)

(a) Recorded on a discounted basis, reflecting a discount rate of 4.0%. Estimate before the effects of discounting was $48 million, which reflects an inflation rate of 2.3%.

(b) Recorded on a discounted basis, reflecting a discount rate of 4.3%. Estimate before the effects of discounting was $49 million, which reflects an inflation rate of 2.3%.

As of December 31, 2005, PECO anticipates that payments related to the discounted environmental investigation and remediation costs, disclosed below on an undiscounted basis, will be:

2006	$	7
2007		11
2008		7
2009		8
2010		6
Remaining years		9
Total payments	$	48

PECO cannot reasonably estimate whether it will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by PECO, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. However, pursuant to a PAPUC order, PECO is currently recovering through regulated gas rates costs associated with the remediation of the MGP sites. See Note 16—Supplemental Financial Information for further information regarding regulatory assets and liabilities.

Leases

Minimum future operating lease payments, including lease payments for vehicles as of December 31, 2005 were:

2006	$	3
2007		1
2008		1
2009		1
2010		1
Remaining years		1
Total minimum future lease payments	$	8

PECO’s rental expense under operating leases totaled $4 million, $4 million and $6 million in 2005, 2004, and 2003, respectively.

342

PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Litigation

PJM Billing Dispute.In December 2004, Exelon filed a complaint against PJM and PPL Electric with the FERC alleging that PJM had overcharged Exelon from April 1998 through May 2003 as a result of a billing error. Specifically, the complaint alleges that PJM mistakenly identified PPL Electric’s Elroy substation transformer as belonging to Exelon and that, as a consequence, during times of congestion, Exelon’s bills for transmission congestion from PJM erroneously reflected energy that PPL Electric took from the Elroy substation and used to serve PPL Electric’s load. The complaint requested the FERC, among other things, to direct PPL Electric to refund to PJM $39.1 million, plus interest of approximately $8 million, and for PJM to refund these same amounts to Exelon.

On September 14, 2005, Exelon and PPL Electric filed a proposed settlement of this matter with the FERC. If the settlement is approved by the FERC, Exelon will receive a total of $40.5 million, plus interest, over the next four years from two funding sources: (a) $33 million from PPL Electric; and (b) $7.5 million from PJM market participants. It is anticipated that approximately 25% of the proposed settlement will be received by PECO. Both charges will be collected and paid by PJM over a four-year period following FERC approval of the settlement with interest on the unpaid principal accruing over the collection and payment period. As Exelon is a market participant in PJM, if this settlement is approved by the FERC, the net amount of the settlement to be received by Exelon will be reduced by Exelon’s portion of the $7.5 million described above.

Pending FERC approval of the settlement, PECO has not recorded any receivables associated with this matter.

Real Estate Tax Appeals.PECO is challenging real estate taxes assessed on nuclear plants. 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. PECO has reached a settlement with the taxing authorities over the Limerick real estate assessments for 1998 and 1999. Pursuant to the settlement agreement, all Limerick tax appeals were dismissed by the state court, and PECO has agreed to an additional payment of approximately $3 million for the two PURTA years. As a result of the Limerick settlement, PECO reduced its real estate tax reserve balance by $6 million in the first quarter of 2005.

PECO believes its reserve balances for other exposures associated with real estate taxes as of December 31, 2005 and 2004 reflect the probable expected outcome of the litigation and appeals proceedings in accordance with SFAS No. 5. The ultimate outcome of such matters, however, could result in unfavorable or favorable adjustments to the consolidated financial statements of PECO and such adjustments could be material.

Reverse-Employment Discrimination Claim. On April 4, 2005, one employee of PECO and four employees of Generation commenced suit in the United States District Court for the Eastern District of Pennsylvania, alleging that they were subjected to a practice of reverse-employment discrimination which denied promotional opportunities to older white male employees, purportedly in violation of various Federal antidiscrimination statutes and the Pennsylvania Human Relations Act. The plaintiffs filed the action individually and on behalf of a putative class that includes all white males currently or previously employed with any Exelon companies in the United States who were at least 40 years old on April 4, 2003 and who either applied for or were eligible to apply for supervisory positions in March 2003 and thereafter, continuing to the present day, and were not selected for these positions. The

343

PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

defendants have filed an answer denying all liability and are proceeding with discovery pertaining to the class allegations and the named plaintiffs’ individual claims. In December 2005, the Court ordered the case to be suspended until April 3, 2006 while the parties attempt to resolve this matter through non-binding mediation. As this case is in the early stages, Exelon cannot predict the outcome; however, Exelon does not expect this claim to have a material adverse effect on Exelon’s financial condition, results of operations or cash flows.

General. PECO is involved in various other litigation matters that are being defended and handled in the ordinary course of business. PECO maintains accruals for such costs that are probable of being incurred and subject to reasonable estimation. The ultimate outcomes of such matters, as well as the matters discussed above, are uncertain and may have a material adverse effect on PECO’s financial condition, results of operations or cash flows.

Fund Transfer Restrictions

Under applicable Federal law, PECO can pay dividends only from retained, undistributed or current earnings. 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, 2005, such capital was $2.8 billion and amounted to about 32 times the liquidating value of the outstanding preferred stock of $87 million. Additionally, 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 PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. At December 31, 2005 and 2004, PECO had retained earnings of $649 million and $607 million, respectively.

Income Taxes

Refund Claims.PECO has entered into several agreements with a tax consultant related to the filing of refund claims with the IRS. PECO previously made refundable prepayments to the tax consultants of $5 million. The fees for these agreements are contingent upon a successful outcome of the claims and are based upon a percentage of the refunds recovered from the IRS, if any. The 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.

Based on negotiations with the IRS during the first half of 2005, PECO believed it would receive a tax refund related to one of its claims and recorded a $6 million (pre-tax) charge related to expected consulting charges through the second quarter of 2005. However, as the result of a recent unfavorable tax court decision involving another utility related to a similar type of refund claim, PECO no longer believes payment of the consulting fees is probable and reversed the $6 million (pre-tax) charge during the third quarter 2005. PECO is unable to predict the final impact of its future negotiations with the IRS on this matter.

344

PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Other Refund Claims.PECO has filed several tax refund claims with Federal and state taxing authorities. PECO is unable to estimate the ultimate outcome of these refund claims and will account for any amount received in the period the matters are settled with the Federal and state taxing authorities.

16. Supplemental Financial Information

Supplemental Income Statement Information

The following tables provide additional information about PECO’s Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003.

	For the Years Ended December 31,
	2005		2004		2003
Depreciation and amortization
Property, plant and equipment(a)	$	157	$	144	$	144
Competitive transition charge		404		367		336
Other regulatory assets		5		7		7
Total depreciation and amortization	$	566	$	518	$	487

(a) Includes amortization of capitalized software costs.

	For the Years Ended December 31,
	2005			2004		2003
Taxes other than income
Utility(a)	$	230		$	205	$	206
Real estate		4			10		(47	)(b)
Payroll		9			10		11
Other		(12	)(c)		11		3
Total taxes other than income	$	231		$	236	$	173

(a) Municipal and state utility taxes are also recorded in revenues on PECO’s Consolidated Statements of Income.

(b) Includes the reduction of a $58 million property tax accrual during 2003.

(c) Reflects a $17 million reduction in 2005 of prior year capital stock tax accruals as a result of a favorable decision from the Pennsylvania Board of Finance and Revenue.

	For the Years Ended December 31,
	2005			2004		2003
Other, net
Investment income	$	6		$	8	$	10
Gain on disposition of assets, net		6			9		—
AFUDC, equity		2			1		—
Interest associated with Federal income taxes		—			—		(14	)
Other		(1	)		—		6
Total other, net	$	13		$	18	$	2

345

PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Supplemental Cash Flow Information

As a result of adopting FIN 47 as of December 31, 2005, PECO recorded a net ARC of $2 million, which was capitalized as an increase to the carrying amount of long-lived assets associated with liabilities recorded for conditional AROs. This amount resulted in a non-cash investing activity. See Note 10—Conditional ARO for additional information on the adoption of FIN 47. In addition to this non-cash activity, the following table provides additional information about PECO’s Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003.

	For the Years Ended December 31,
	2005		2004		2003
Cash paid during the year
Interest (net of amount capitalized)	$	281	$	298	$	346
Income taxes (net of refunds)		430		394		269

Supplemental Balance Sheet Information

The following table provides additional information about liabilities recorded within PECO’s Consolidated Balance Sheets as of December 31, 2005 and 2004.

	December 31,
	2005		2004
Accrued expenses
Taxes accrued	$	42	$	140
Interest accrued		20		12
Other		30		65
Total accrued expenses	$	92	$	217

The following table provides additional information about accumulated other comprehensive income recorded within PECO’s Consolidated Balance Sheets as of December 31, 2005 and 2004.

	December 31,
	2005		2004
Accumulated other comprehensive income
Net unrealized gain on cash-flow hedges	$	7	$	10
Total accumulated other comprehensive income	$	7	$	10

346

PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

The following tables provide information about the regulatory assets and liabilities of PECO as of December 31, 2005 and 2004.

	December 31,
	2005			2004
Regulatory assets (liabilities)
Competitive transition charges	$	3,532		$	3,936
Deferred income taxes		781			747
Non-pension postretirement benefits		45			52
Reacquired debt costs		36			42
MGP regulatory asset		26			32
DOE facility decommissioning		13			19
Conditional asset retirement obligations		13			—
Nuclear decommissioning		(68	)		(46	)
Other		8			8
Long-term regulatory assets		4,386			4,790
Deferred energy costs (current asset)		39			25
Total	$	4,425		$	4,815

Competitive transition charges. These charges represent PECO’s stranded costs that the PAPUC determined would 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, an unconsolidated 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 by which the regulator allows for the recovery of income taxes and how income taxes would be recorded by unregulated entities. 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 rate-making policies of the PAPUC, as well as the revenue impacts thereon, and assume continued recovery of these costs in future rates. See Note 8—Income Taxes for additional information.

Non-pension postretirement benefits. These costs are the result of transitioning to SFAS No. 106 in 1993, which are recoverable in rates through 2012.

Reacquired debt costs. The reacquired debt 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 MGP-related environmental remediation costs which are recoverable through regulated gas rates.

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.

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PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Conditional asset retirement obligations. These costs represent future removal costs associated with asset retirement obligations which will be collected over the remaining lives of the underlying assets. See Note 10—Conditional ARO for further information.

Nuclear decommissioning. Generation is responsible for decommissioning the nuclear plants formerly owned by PECO. These amounts represent future nuclear decommissioning costs that exceed (regulatory asset) or are less than (regulatory liability) the associated decommissioning trust fund assets. Generation and PECO believe the trust fund assets, including prospective earnings thereon and any future collections from customers, will equal the associated future decommissioning costs at the time of decommissioning. See Note 9—Nuclear Decommissioning for further information.

Deferred energy costs (current asset). These costs represent fuel costs recoverable under the purchase gas adjustment clause.

Recovery of regulatory assets.The regulatory assets related to deferred income taxes and non-pension post retirement benefits did not require a cash outlay of investor supplied funds; consequently, these costs are not earning a rate of return. Recovery of the regulatory assets for competitive transition charges, reacquired debt costs, MGP remediation costs, DOE facility decommissioning and deferred energy costs is provided for through regulated revenue sources. Therefore, these costs are earning a rate of return.

17. Related Party Transactions

Effective July 1, 2003 PECO Trust IV was deconsolidated from the financial statements of PECO in conjunction with the adoption of FIN 46. Effective December 31, 2003, PETT, PECC, and PECO Trust III were deconsolidated from the financial statements of PECO in conjunction with the adoption of FIN 46-R. Prior periods were not restated.

PECO’s financial statements reflect related-party transactions with its unconsolidated financing subsidiaries as presented in the tables below:

	For Year Ended December 31,
	2005		2004		2003
Operating revenues from affiliates
PETT(a)	$	9	$	10	$	—
Interest expense to affiliates
PETT		212		235		—
PECO Trust III		6		6		—
PECO Trust IV		6		6		3
Equity in losses of unconsolidated affiliates
PETT		16		25		—

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PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

	December 31,
	2005		2004
Investment in affiliates
PETT	$	63	$	77
PECO Energy Capital Corp		4		4
PECO Trust IV		6		6
Payables to affiliates (current)
PECO Trust III		1		1
Long-term debt to PETT and other financing trusts (including due within one year)
PETT		2,975		3,456
PECO Trust III		81		81
PECO Trust IV		103		103

(a) PECO receives a monthly service fee from PETT based on a percentage of the outstanding balance of all series of transition bonds.

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,
	2005		2004		2003
Operating revenues from affiliates
Generation(a)	$	8	$	9	$	10
Other		—		—		1
Purchased power from affiliate
Generation(b)		1,670		1,447		1,433
Fuel from affiliate
Generation(c)		1		17		—
Operating and maintenance from affiliates
BSC(d)		108		106		50
Generation		1		1		—
Enterprises(e)		—		—		2
ComEd(f)		—		—		5
Interest income from affiliates
Other		1		—		—
Capitalized costs
BSC(d)		41		22		4
Enterprises(e)		—		—		15
Cash dividends paid to parent		469		391		322

	December 31,
	2005		2004
Receivable from affiliate (current)
BSC	$	13	$	—
Contributions to Exelon intercompany money pool(g)		8		34
Receivable from affiliate (noncurrent)
Generation decommissioning(h)		68		46
Payables to affiliates (current)
Generation(b)		151		125
BSC(d)		26		20
Shareholders’ equity—receivable from parent(i)		1,232		1,482

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PECO Energy Company and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

(a) PECO provides energy to Generation for Generation’s own use.

(b) PECO has entered into a PPA with Generation. See Note 15—Commitments and Contingencies for more information regarding the PPA.

(c) Effective April 1, 2004, PECO entered into a one-year gas procurement agreement with Generation.

(d) PECO receives a variety of corporate support services from Exelon Business Services Company (BSC), including legal, human resources, financial, information technology, supply management services, planning and engineering of delivery systems, management of construction, maintenance and operations of the transmission and delivery systems and management of other support services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(e) Prior to 2004, PECO received services from Exelon Enterprises Company, LLC (Enterprises) for construction, which were capitalized, and the deployment of automated meter reading technology, which was expensed. This entity was sold by Exelon in 2004.

(f) In 2003, ComEd provided hurricane restoration services to PECO during Hurricane Isabel.

(g) PECO participates in Exelon’s intercompany money pool. PECO earns interest on its contributions to the money pool at a market rate of interest.

(h) PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO’s customers. See Note 9—Nuclear Decommissioning for additional information.

(i) 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 2006 through 2010.

18. 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
	2005		2004		2005		2004		2005		2004
Quarter ended:
March 31	$	1,295	$	1,239	$	274	$	276	$	128	$	131
June 30		1,044		1,032		225		230		109		99
September 30		1,322		1,124		320		301		165		138
December 31		1,249		1,092		231		207		111		84

19. Subsequent Events

On February 1, 2006, PECO was notified that the Pennsylvania (PA) Board of Finance and Revenue (BF&R) approved, in a 6-0 decision, PECO’s request for resettlement of its 2001 and 2002 Capital Stock Tax and Franchise Tax (CS/FT) liability. Based on this approval, PECO reduced liabilities associated with its previously estimated CS/FT liabilities for the years 2001 through 2004 by a total of $11 million (after tax), which has been reflected in PECO’s Consolidated Statements of Income for the year ended December 31, 2005 and Consolidated Balance Sheets as of December 31, 2005.

The basis for computing the CS/FT includes a five-year rolling average of the legal entity’s net income. PECO had appealed to the PA Department of Revenue regarding the inclusion of certain income included in the calculation of these taxes.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

Generation

Executive Overview

A discussion of items pertinent to Generation’s executive overview is set forth under “EXELON CORPORATION—Executive Overview” of this Report.

Results of Operation

Year Ended December 31, 2005 Compared To Year Ended December 31, 2004

Generation	2005			2004			Favorable (unfavorable) variance
Operating revenues	$	9,046		$	7,703		$	1,343
Operating expenses
Purchased power		2,569			2,307			(262	)
Fuel		1,913			1,704			(209	)
Operating and maintenance		2,288			2,201			(87	)
Depreciation and amortization		254			286			32
Taxes other than income		170			166			(4	)
Total operating expenses		7,194			6,664			(530	)
Operating income		1,852			1,039			813
Other income and deductions
Interest expense		(128	)		(103	)		(25	)
Equity in earnings of unconsolidated affiliates		(1	)		(14	)		13
Other, net		95			130			(35	)
Total other income and deductions		(34	)		13			(47	)
Income from continuing operations before income taxes and minority interest		1,818			1,052			766
Income taxes		709			401			(308	)
Income from continuing operations before minority interest		1,109			651			458
Minority interest		—			6			(6	)
Income from continuing operations		1,109			657			452
Discontinued operations
Loss from discontinued operations		—			(45	)		45
Gain on disposal of discontinued operations		24			—			24
Income taxes		5			(29	)		(34	)
Income (loss) from discontinued operations		19			(16	)		35
Income before cumulative effect of a change in accounting principle		1,128			641			487
Cumulative effect of a change in accounting principle		(30	)		32			(62	)
Net income	$	1,098		$	673		$	425

A discussion of Generation’s results of operations for 2005 compared to 2004 is set forth under “Results of Operations—Generation” in “EXELON CORPORATION—Results of Operations” of this Report.

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Results of Operation

Year Ended December 31, 2004 Compared To Year Ended December 31, 2003

Generation	2004			2003			Favorable (unfavorable) variance
Operating revenues	$	7,703		$	8,135		$	(432	)
Operating expenses
Purchased power		2,307			3,587			1,280
Fuel		1,704			1,533			(171	)
Operating and maintenance		2,201			1,866			(335	)
Impairment of Boston Generating, LLC long-lived assets		—			945			945
Depreciation and amortization		286			199			(87	)
Taxes other than income		166			120			(46	)
Total operating expenses		6,664			8,250			1,586
Operating income (loss)		1,039			(115	)		1,154
Other income and deductions
Interest expense		(103	)		(88	)		(15	)
Equity in earnings (losses) of unconsolidated affiliates		(14	)		49			(63	)
Other, net		130			(262	)		392
Total other income and deductions		13			(301	)		314
Income (loss) from continuing operations before income taxes and minority interest		1,052			(416	)		1,468
Income taxes		401			(179	)		(580	)
Income from continuing operations before minority interest		651			(237	)		888
Minority interest		6			(4	)		10
Income (loss) from continuing operations		657			(241	)		898
Discontinued operations
Loss from discontinued operations		(45	)		—			(45	)
Income taxes		(29	)		—			29
Loss from discontinued operations		(16	)		—			(16	)
Income (loss) before cumulative effect of changes in accounting principles		641			(241	)		882
Cumulative effect of changes in accounting principles		32			108			(76	)
Net income (loss)	$	673		$	(133	)	$	806

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Operating Revenues

Operating revenues decreased in 2004 as compared to 2003, primarily as a result of the adoption of EITF 03-11. The adoption of EITF 03-11 resulted in a net decrease in revenues of $980 million in 2004 as compared with the prior year. Generation’s sales in 2004 and 2003 were as follows:

Revenue (in millions)	2004		2003		Variance			% Change
Electric sales to affiliates(a)	$	3,749	$	4,036	$	(287	)	(7.1%	)
Wholesale and retail electric sales(b)		3,227		3,861		(634	)	(16.4%	)
Total energy sales revenue		6,976		7,897		(921	)	(11.7%	)
Retail gas sales		448		—		448		n.m.
Trading portfolio		—		1		(1	)	(100.0%	)
Other revenue(c)		279		237		42		17.7%
Total revenue	$	7,703	$	8,135	$	(432	)	(5.3%	)
Sales (in GWhs)	2004		2003		Variance			% Change
Sales to affiliates(a)		110,465		117,405		(6,940	)	(5.9%	)
Wholesale and retail electric sales(b)		92,134		107,267		(15,133	)	(14.1%	)
Total sales		202,599		224,672		(22,073	)	(9.8%	)

(a) Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail electric sales.

(b) Includes retail electric sales of Exelon Energy Company in 2004.

(c) Includes sales related to tolling agreements and fossil fuel sales.

Trading volumes of 24,001 GWhs and 32,584 GWhs for the years ended December 31, 2004 and 2003, respectively, are not included in the table above. The decrease in trading volume is a result of reduced volumetric and VAR trading limits in 2004, which are set by the Exelon Risk Management Committee and approved by the Board of Directors.

Electric Sales to Affiliates.Revenue from sales to affiliates decreased primarily as a result of the transfer of Exelon Energy Company to Generation effective January 1, 2004. Sales to Exelon Energy Company are no longer reported as affiliate revenue by Generation. Revenue from sales to Exelon Energy Company for the year ended December 31, 2003 was $209 million.

Sales to Energy Delivery declined $76 million in 2004 as compared to the prior year, which further contributed to the decrease in sales to affiliates. The lower sales to Energy Delivery were primarily driven by cooler than normal summer weather and lower average transfer prices in 2004 as compared to the prior year.

Wholesale and Retail Electric Sales.The changes in Generation’s wholesale and retail electric sales for the year ended December 31, 2004 compared to the same period in 2003, consisted of the following:

	Variance
Effects of EITF 03-11 adoption (a)	$	(966	)
Sale of Boston Generating		(370	)
Addition of Exelon Energy Company and AmerGen operations		424
Other operations		278
Decrease in wholesale and retail electric sales	$	(634	)

(a) Does not include $14 million of EITF 03-11 reclassifications related to fuel sales that are included in other revenues.

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As previously described, the adoption of EITF 03-11 on January 1, 2004 resulted in the netting of certain revenues and the associated purchased power and fuel expense in 2004. The sale of Boston Generating in May 2004 resulted in less revenue from this entity in 2004 compared to the prior year. The acquisition of Exelon Energy and AmerGen resulted in increased market and retail electric sales of approximately $424 million compared to the prior year.

The remaining increase in wholesale and retail electric sales was primarily due to higher volumes sold to the market at overall higher prices. The increase in market prices was primarily driven by higher coal prices in the Midwest region and higher oil and gas prices in the Mid-Atlantic region.

Retail Gas Sales. Retail gas sales increased $448 million as a result of the transfer of Exelon Energy Company to Generation as of January 1, 2004.

Other.The remaining increase in other revenue includes increased sales from tolling agreements offset by a decrease in fossil fuel revenue.

Purchased Power and Fuel Expense

Generation’s supply of sales in 2004 and 2003, excluding the trading portfolio, was as follows:

Supply of Sales (in GWhs)	2004	2003	% Change
Nuclear generation(a)	136,621	117,502	16.3	%
Purchases—non-trading portfolio(b)	48,968	82,860	(40.9	%)
Fossil and hydroelectric generation(c, d)	17,010	24,310	(30.0	%)
Total supply	202,599	224,672	(9.8	%)

(a) Excludes AmerGen for 2003. AmerGen generated 20,135 GWhs during the year ended December 31, 2004.

(b) Sales in 2004 do not include 25,464 GWhs that were netted with purchased power GWhs as a result of the reclassification of certain hedging activities in accordance with EITF 03-11. Includes PPAs with AmerGen, which represented 12,667 GWhs in 2003.

(c) Fossil and hydroelectric supply mix changed as a result of decreased fossil fuel generation due to the sale of Boston Generating in May 2004.

(d) Excludes Sithe and Generation’s investment in TEG and TEP.

The changes in Generation’s purchased power and fuel expense for the year ended December 31, 2004 compared to the same period in 2003 consisted of the following:

	Variance
Effects of the adoption of EITF 03-11	$	(980	)
Sale of Boston Generating		(290	)
Midwest Generation		(122	)
Mark-to-market adjustments on hedging activity		(14	)
Price		(13	)
Volume		267
Addition of AmerGen and Exelon Energy Company		124
Other		(81	)
Decrease in purchased power and fuel expense	$	(1,109	)

Adoption of EITF 03-11.The adoption of EITF 03-11 resulted in a decrease in purchased power and fuel expense of $980 million.

Sale of Boston Generating.The decrease in fuel and purchased power expense for Boston Generating is due primarily to the sale of the business in May 2004.

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Midwest Generation.The volume of purchased power acquired from Midwest Generation declined in 2004 as a result of Generation exercising its option to reduce the capacity purchased from Midwest Generation, as announced in 2003.

Hedging Activity.Mark-to-market losses on hedging activities at Generation were $2 million for the year ended December 31, 2004 compared to losses of $16 million for 2003. Hedging activities in 2004 relating to Boston Generating operations accounted for a gain of $4 million and hedging activities relating to other Generation operations in 2004 accounted for a loss of $6 million.

Price. The decrease reflects the forward hedging of fuel at lower costs than 2003 realized costs.

Volume. Generation experienced increases in purchased power and fuel expense due to increased market and retail electric sales throughout its various sales regions.

Addition of AmerGen and Exelon Energy Company.Due to the transfer of Exelon Energy Company to Generation effective January 1, 2004, fuel expense increased $468 million as fuel purchases made by Exelon Energy Company did not previously affect Generation’s results. As a result of Generation’s acquisition of the remaining 50% interest in AmerGen in December 2003, purchased power decreased $379 million in 2004. In prior periods, Generation reported energy purchased from AmerGen as purchased power expense. The decrease in purchase power from the acquisition of the remaining 50% of AmerGen was partially offset by an increase of $35 million in AmerGen’s nuclear fuel expense.

Other. Other decreases in purchased power and fuel expense were primarily due to lower transmission expense resulting from reduced inter-region transmission charges, primarily associated with ComEd’s integration into PJM.

Generation’s average margins per MWh sold for the years ended December 31, 2004 and 2003 were as follows:

($/MWh)	2004		2003		% Change
Average electric revenue
Electric sales to affiliates(a)	$	33.94	$	34.38	(1.3	%)
Wholesale and retail electric sales(b)		35.03		35.99	(2.7	%)
Total—excluding the trading portfolio		34.43		35.15	(2.0	%)
Average electric supply cost—excluding the trading portfolio(c)	$	17.60	$	22.79	(22.8	%)
Average margin—excluding the trading portfolio	$	16.83	$	12.36	36.2	%

(a) Includes sales to Exelon Energy Company during 2003. As of January 1, 2004, Exelon Energy Company became part of Generation and is presented as retail sales.

(b) Includes retail electric sales of Exelon Energy Company in 2004.

(c) Average electric supply cost includes purchased power and fuel costs associated with electric sales and PPAs with AmerGen in 2003. Average electric supply cost does not include purchased power and fuel cost associated with retail gas sales.

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Operating and Maintenance

The changes in operating and maintenance expense for the year ended December 31, 2004 compared to the same period in 2003 consisted of the following:

	Variance
Addition of AmerGen and Exelon Energy Company	$	345
Refueling outage costs(a)		50
Decommissioning-related costs(b)		50
Pension, payroll and benefit costs, primarily associated with The Exelon Way		(84	)
DOE Settlement(c)		(52	)
Sale of Boston Generating		(12	)
Other		38
Increase in operating and maintenance expense	$	335

(a) Includes refueling outage expense of $43 million at AmerGen not included in 2003.

(b) Includes $40 million due to AmerGen asset retirement obligation accretion not included in 2003.

(c) See Note 13 of Generation’s Notes to Consolidated Financial Statements for further discussions of the spent nuclear fuel storage settlement agreement with the DOE.

The increase in operating and maintenance expense is primarily due to the inclusion of AmerGen and Exelon Energy Company in Generation’s consolidated results for 2004. Decommissioning- related costs increased primarily due to the inclusion of AmerGen in 2004 compared to the prior year. Accretion expense includes accretion of the asset retirement obligation and adjustments to offset the earnings impacts of certain decommissioning-related activities, including revenues earned from ComEd and PECO, income taxes and depreciation of the asset retirement cost asset (ARC) to zero. The increase in operating and maintenance expense was partially offset with reductions in payroll-related costs due to the implementation of the programs associated with The Exelon Way, the sale of Boston Generating in May 2004 and the settlement with the DOE to reimburse Generation for costs associated with storage of spent nuclear fuel.

Nuclear fleet operating data and purchased power costs data for the year ended December 31, 2004 and 2003 were as follows:

	2004		2003
Nuclear fleet capacity factor(a)		93.5%		93.4%
Nuclear fleet production cost per MWh(a)	$	12.43	$	12.53
Average purchased power cost for wholesale operations per MWh(b)	$	47.11	$	43.29

(a) Includes AmerGen and excludes Salem, which is operated by PSEG Nuclear.

(b) Includes PPAs with AmerGen in 2003.

The higher nuclear capacity factor is primarily due to ten fewer unplanned outages which offset the impact of one additional planned refuel outage. The lower production cost in 2004 as compared to 2003 is primarily due to lower fuel costs and the impact of the spent fuel storage cost settlement agreement with the DOE which offset the added cost for one additional planned refuel outage and costs associated with the Dresden generator repairs during outages in the fourth quarter of 2004.

In 2004 as compared to 2003, the Quad Cities Units intermittently operated at pre-Extended Power Uprate (EPU) generation levels due to performance issues with their steam dryers.

Impairment of the Long-Lived Assets of Boston Generating

In connection with the decision to transition out of the ownership of Boston Generating during the third quarter of 2003, Generation recorded a long-lived asset impairment charge of $945 million ($573

356

million net of income taxes). See Note 2 of Generation’s Notes to Consolidated Financial Statements for further discussion of the sale of Generation’s ownership interest in Boston Generating.

Depreciation and Amortization

The increase in depreciation and amortization expense in 2004 as compared to 2003 was primarily due to the immediate expensing of an asset retirement cost (ARC), totaling $49 million, recorded in 2004 for which no useful life remains. The ARC was originally recorded in accordance with SFAS No. 143, which requires the establishment of an asset to offset the impact of an increased asset retirement obligation (ARO). See Note 13 of Generation’s Notes to Consolidated Financial Statements for more information on the 2004 update to the ARO and ARC. The remaining increase was due to capital additions and the consolidation of AmerGen and Exelon Energy. These increases were partially offset by a decrease in depreciation expense related to the Boston Generating facilities, which were sold in May 2004.

Taxes Other Than Income

Taxes other than income increased in 2004 compared to 2003 due primarily to $26 million of additional payroll and property taxes incurred from the consolidation of AmerGen and Exelon Energy. The remaining increase primarily resulted from a $15 million reduction to reserves recorded in 2003 for exposures associated with property taxes.

Interest Expense

The increase in interest expense in 2004 as compared to 2003 was primarily related to additional expense incurred from the purchase of British Energy’s interest in AmerGen and the issuance of $500 million of Senior Notes in December 2003. The increase was partially offset by a reduction in interest expense of $12 million related to the Boston Generating project debt being deconsolidated in May 2004.

Equity in Earnings of Unconsolidated Affiliates

The decrease in equity in earnings of unconsolidated affiliates in 2004 as compared to 2003 was due to a $47 million decrease resulting from Generation’s consolidation of AmerGen in 2004 following the purchase of British Energy’s 50% interest in AmerGen in December 2003 and the consolidation of Sithe in 2004. Equity in earnings of unconsolidated affiliates in 2004 represents equity earnings from TEG and TEP following the transfer of ownership in Sithe International in the fourth quarter of 2004, and prior to the transfer, relates to earnings recorded at Sithe for Sithe’s 49.5% interests in TEG and TEP.

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Other, Net

The components of other, net for 2004 as compared to 2003 are as follows:

Other, Net	2004			2003			Variance
Gain on sale of Boston Generating(a)	$	85		$	—		$	85
Decommissioning-related activities:
Decommissioning trust fund income(b)		194			79			115
Decommissioning trust fund income—AmerGen(b)		43			—			43
Other-than-temporary impairment of decommissioning trust funds(c)		(268	)		—			(268	)
Contractual offset to decommissioning-related activities(d)		66			(79	)		145
Gain on sale of assets		6			—			6
Impairment of investment in Sithe		—			(255	)		255
Other		4			(7	)		11
Total	$	130		$	(262	)	$	392

(a) See Note 2 of Generation’s Notes to the Consolidated Financial Statements for further discussion of Generation’s sale of Boston Generating.

(b) Includes investment income and realized gains/(losses).

(c) Includes other-than-temporary impairments totaling $255 million, $5 million and $8 million on nuclear decommissioning trust funds for the former ComEd, former PECO and AmerGen units respectively.

(d) Includes the elimination of non-operating decommissioning-related activity for those units that are subject to contractual accounting, including the elimination of decommissioning trust fund income and other-than-temporary impairments for certain nuclear units. See Notes 13 and 15 of Generation’s Notes to Consolidated Financial Statements for more information regarding the contractual accounting applied for certain nuclear units.

The increase in other, net in 2004 as compared to 2003 was primarily due to the $85 million gain ($52 million, net of taxes) on the sale of Boston Generating recorded in 2004, a $255 million impairment charge in 2003 related to Generation’s equity investment in Sithe Energies, Inc. and a $25 million loss resulting from the purchase and subsequent sale of 50% of the assets of Sithe to Reservoir (see Note 3 of Generation’s Notes to Consolidated Financial Statements) in 2003. The remaining increase was primarily due to a $35 million increase in decommissioning trust fund investment income primarily related to AmerGen.

Effective Income Tax Rate

The effective income tax rate was 38% for 2004 compared to 43% for 2003. The decrease in the effective rate was primarily attributable to income taxes associated with nuclear decommissioning trust fund activity, income tax deductions related to non-taxable employee benefits and the dilution of the permanent income tax benefits due to the increase in pre-tax income in 2004.

Discontinued Operations

The loss from discontinued operations includes the results of operations of Sithe from April 1, 2004 through the end of the year and the results from AllEnergy, a former subsidiary of Exelon Energy. Sithe’s net impact to Generation was a loss of $19 million in 2004, while AllEnergy produced $3 million of net income in 2004. (See Note 21 of Generation’s Notes to Consolidated Financial Statements)

Cumulative Effect of Changes in Accounting Principles

On March 31, 2004, Generation adopted FIN 46-R, resulting in a benefit of $32 million (net of income taxes of $22 million). On January 1, 2003, Generation adopted SFAS No. 143 resulting in a benefit of $108 million (net of income taxes of $70 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

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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. 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 the capital markets at reasonable terms, Generation has access to a revolving credit facility that Generation currently utilizes to support is commercial paper program. See the “Credit Matters” section of “Liquidity and Capital Resources” for further discussion.

Capital resources are used primarily to fund Generation’s capital requirements, including construction, retirement of debt, the payment of distributions to Exelon, contributions to Exelon’s pension plans and investments in new and existing ventures. Future acquisitions could require external financing or borrowings or capital contributions from Exelon.

Cash Flows from Operating Activities

A discussion of items pertinent to Generation’s cash flows from operating activities is set forth under “Cash Flows from Operating Activities” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

Cash Flows from Investing Activities

A discussion of items pertinent to Generation’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

Cash Flows from Financing Activities

A discussion of items pertinent to Generation’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

Credit Matters

A discussion of credit matters pertinent to Generation is set forth under “Credit Matters” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations

A discussion of Generation’s contractual obligations, commercial commitments and off-balance sheet obligations is set forth under “Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations” in “EXELON CORPORATION—Liquidity and Capital Resources” of this Report.

Critical Accounting Policies and Estimates

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

New Accounting Pronouncements

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK—Generation

Generation is exposed to market risks associated with commodity price, credit, interest rates and equity price. These risks are described above under “Quantitative and Qualitative Disclosures about Mark Risk—Exelon.”

359

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Generation

Report of Independent Registered Public Accounting Firm

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 its subsidiaries (Generation) at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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 the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 asset retirement obligations as of January 1, 2003, its method of accounting for variable interest entities in 2004; and its method of accounting for conditional asset retirement obligations as of December 31, 2005.

PricewaterhouseCoopers LLP

Chicago, Illinois

February 15, 2006

360

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Income

	For the Year Ended December 31,
(in millions)	2005			2004			2003
Operating revenues
Operating revenues	$	4,198		$	3,862		$	4,010
Operating revenues from affiliates		4,848			3,841			4,125
Total operating revenues		9,046			7,703			8,135
Operating expenses
Purchased power		2,569			2,297			3,158
Purchased power from affiliates		—			10			429
Fuel		1,913			1,704			1,533
Impairment of Boston Generating, LLC long-lived assets		—			—			945
Operating and maintenance		2,051			1,962			1,717
Operating and maintenance from affiliates		237			239			149
Depreciation and amortization		254			286			199
Taxes other than income		170			166			120
Total operating expense		7,194			6,664			8,250
Operating income (loss)		1,852			1,039			(115	)
Other income and deductions
Interest expense		(125	)		(100	)		(75	)
Interest expense to affiliates		(3	)		(3	)		(13	)
Equity in earnings (losses) of unconsolidated affiliates		(1	)		(14	)		49
Interest income from affiliates		—			—			1
Other, net		95			130			(263	)
Total other income and deductions		(34	)		13			(301	)
Income (loss) from continuing operations before income taxes and minority interest		1,818			1,052			(416	)
Income taxes		709			401			(179	)
Income (loss) from continuing operations before minority interest		1,109			651			(237	)
Minority interest		—			6			(4	)
Income (loss) from continuing operations		1,109			657			(241	)
Discontinued operations
Loss from discontinued operations		—			(45	)		—
Gain on disposal of discontinued operations		24			—			—
Income taxes		5			(29	)		—
Income (loss) from discontinued operations		19			(16	)		—
Income (loss) before cumulative effect of changes in accounting principles		1,128			641			(241	)
Cumulative effect of changes in accounting principles (net of income taxes of $(19), $22 and $70, respectively)		(30	)		32			108
Net income (loss)	$	1,098		$	673		$	(133	)

See Notes to Consolidated Financial Statements

361

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Cash Flows

	For the Year Ended December 31,
(in millions)	2005			2004			2003
Cash flows from operating activities
Net income (loss)	$	1,098		$	673		$	(133	)
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel		886			923			754
Cumulative effect of changes in accounting principles (net of income taxes)		30			(32	)		(108	)
Impairment of investment in Sithe Energies, Inc.		—			—			255
Impairment of long-lived assets		—			—			952
Deferred income taxes and amortization of investment tax credits		330			124			60
Provision for uncollectible accounts		—			2			(2	)
(Gain) loss on sale of investments		(24	)		(91	)		25
Other decommissioning-related activities		(15	)		169			37
Equity in (earnings) losses of unconsolidated affiliates		1			14			(49	)
Net realized (gains) losses on nuclear decommissioning trust funds		(49	)		(72	)		16
Other non-cash operating activities		12			(47	)		(10	)
Changes in assets and liabilities:
Accounts receivable		(64	)		(67	)		(23	)
Receivables and payables to affiliates, net		(101	)		11			195
Inventories		(82	)		(35	)		(29	)
Other current assets		(148	)		22			37
Accounts payable, accrued expenses and other current liabilities		143			45			11
Disbursement of counterparty collateral		(244	)		42			(72	)
Collections of counterparty collateral		57			31			5
Income taxes		178			228			(361	)
Net realized and unrealized mark-to-market and hedging transactions		(6	)		37			(9	)
Pension and non-pension postretirement benefits obligation		(865	)		(92	)		(50	)
Other noncurrent assets and liabilities		(165	)		62			(48	)
Net cash flows provided by operating activities		972			1,947			1,453
Cash flows from investing activities
Capital expenditures		(1,067	)		(960	)		(953	)
Proceeds from liquidated damages		—			—			92
Proceeds from nuclear decommissioning trust fund sales		5,274			2,320			2,341
Investment in nuclear decommissioning trust funds		(5,501	)		(2,587	)		(2,564	)
Acquisition of businesses, net of cash acquired		(97	)		—			(272	)
Proceeds from sales of investments		103			24			82
Net cash increase from consolidation of Sithe Energies, Inc. and Exelon Energy Company		—			24			—
Change in restricted cash		(1	)		36			(63	)
Other investing activities		(5	)		40			36
Net cash flows used in investing activities		(1,294	)		(1,103	)		(1,301	)
Cash flows from financing activities
Issuance of long-term debt		—			157			1,066
Change in short-term debt		311			—			—
Retirement of long-term debt		(14	)		(62	)		(570	)
Change in note payable, affiliate		(191	)		(162	)		87
Payment on acquisition note payable to Sithe Energies, Inc.		—			(27	)		(446	)
Distribution to member		(857	)		(662	)		(189	)
Contribution from member		843			17			—
Other financing activities		1			—			—
Net cash flows (used in) provided by financing activities		93			(739	)		(52	)
Increase (decrease) in cash and cash equivalents		(229	)		105			100
Cash and cash equivalents at beginning of period		263			158			58
Cash and cash equivalents at end of period	$	34		$	263		$	158

See Notes to Consolidated Financial Statements

362

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Balance Sheets

	December 31,
(in millions)	2005			2004
Assets
Current assets
Cash and cash equivalents	$	34		$	263
Restricted cash and investments		3			26
Accounts receivable, net
Customer		585			525
Other		109			209
Mark-to-market derivative assets		916			403
Receivables from affiliates		411			332
Inventories, at average cost
Fossil fuel		160			112
Materials and supplies		290			255
Deferred income taxes		35			48
Prepayments and other current assets		497			148
Total current assets		3,040			2,321
Property, plant and equipment, net		7,464			7,536
Deferred debits and other assets
Nuclear decommissioning trust funds		5,585			5,262
Investments		120			103
Receivable from affiliate		—			11
Prepaid pension asset		1,013			199
Mark-to-market derivative assets		286			373
Other		216			633
Total deferred debits and other assets		7,220			6,581
Total assets	$	17,724		$	16,438
Liabilities and member’s equity
Current liabilities
Long-term debt due within one year	$	12		$	47
Accounts payable		954			856
Mark-to-market derivative liabilities		1,282			598
Payables to affiliates		4			42
Borrowings from Exelon intercompany money pool		92			283
Commercial paper		311			—
Accrued expenses		415			367
Other		330			223
Total current liabilities		3,400			2,416
Long-term debt		1,788			2,583
Deferred credits and other liabilities
Asset retirement obligation		3,986			3,980
Pension obligation		13			21
Non-pension postretirement benefits obligation		541			584
Spent nuclear fuel obligation		906			878
Deferred income taxes		663			506
Unamortized investment tax credits		202			210
Payables to affiliates		1,503			1,479
Mark-to-market derivative liabilities		460			323
Other		280			375
Total deferred credits and other liabilities		8,554			8,356
Total liabilities		13,742			13,355
Commitments and contingencies
Minority interest of consolidated subsidiary		2			44
Member’s equity
Membership interest		3,220			2,361
Undistributed earnings		1,002			761
Accumulated other comprehensive loss		(242	)		(83	)
Total member’s equity		3,980			3,039
Total liabilities and member’s equity	$	17,724		$	16,438

See Notes to Consolidated Financial Statements

363

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Changes in Member’s Equity

(in millions)	Membership Interest			Undistributed Earnings			Accumulated Other Comprehensive Income (Loss)			Total Member’s Equity
Balance, December 31, 2002	$	2,296		$	924		$	(321	)	$	2,899
Net loss		—			(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
Net income		—			673			—			673
Non-cash distribution to member		—			(9	)		—			(9	)
Distribution to member		(157	)		(505	)		—			(662	)
Transfer of Exelon Energy		(4	)		—			2			(2	)
Consolidation of Sithe in accordance with FIN 46-R		—			—			(6	)		(6	)
Contribution from member		6			—			—			6
Allocation of tax benefit from member		26			—			—			26
Other comprehensive income, net of income taxes of $30		—			—			57			57
Balance, December 31, 2004		2,361			761			(83	)		3,039
Net income		—			1,098			—			1,098
Distribution to member		—			(857	)		—			(857	)
Contribution from member		843			—			—			843
Allocation of tax benefit from member		16			—			—			16
Other comprehensive loss, net of income taxes of ($112)		—			—			(159	)		(159	)
Balance, December 31, 2005	$	3,220		$	1,002		$	(242	)	$	3,980

See Notes to Consolidated Financial Statements

364

Exelon Generation Company, LLC and Subsidiary Companies

Consolidated Statements of Comprehensive Income

	For the Years Ended December 31,
(in millions)	2005			2004		2003
Net income (loss)	$	1,098		$	673	$	(133	)
Other comprehensive income (loss)
SFAS No. 143 transition adjustment, net of income taxes of $167		—			—		168
Change in net unrealized gain (loss) on cash-flow hedges, net of income taxes of $(116), $8 and $(15), respectively		(172	)		7		(21	)
Foreign currency translation, net of income taxes of $0, $0 and $0, respectively		(1	)		1		—
Unrealized gain on marketable securities, net of income taxes of $4, $31 and $27, respectively		14			49		38
Total other comprehensive income (loss)		(159	)		57		185
Total comprehensive income	$	939		$	730	$	52

See Notes to Consolidated Financial Statements

365

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements

(Dollars in millions unless otherwise noted)

1. Significant Accounting Policies

Description of Business

Exelon Generation Company, LLC (Generation) is a limited liability company engaged principally in the production and wholesale marketing and sale of electricity in various regions of the United States. Generation is wholly owned by Exelon Corporation (Exelon). Generation has numerous wholly owned subsidiaries. These subsidiaries were primarily established to hold certain hydroelectric, intermediate and peaking-unit facilities, as well as the 49.5% interests in Termoeléctrica del Golfo (TEG) and Termoeléctrica Peñoles (TEP), two 230 MW projects in Mexico that commenced commercial operations in the second quarter of 2004. The interests in TEG and TEP were acquired from Sithe Energies Inc. (Sithe) in the fourth quarter of 2004. In addition, Generation also has a finance company subsidiary, Generation Finance Company, LLC, which provides certain financing for Generation’s other subsidiaries. Effective January 1, 2004, Exelon Energy Company (Exelon Energy), which had been part of Exelon’s Enterprise business segment, became part of Generation. See Note 3—Acquisitions and Dispositions for information regarding the acquisition disposition of Generation businesses.

Basis of Presentation

The consolidated financial statements include the accounts of entities in which Generation has a controlling financial interest and its proportionate interests in jointly owned electric utility plants, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% or a risk and rewards model that identifies Generation as the primary beneficiary of the variable interest entity. Investments and joint ventures in which Generation does not have a controlling financial interest are accounted for under the equity or cost methods of accounting.

Generation owns 100% of all significant consolidated subsidiaries, either directly or indirectly, except for Southeast Chicago Energy Project, LLC (SCEP), of which Generation owns 72%. Generation has reflected the third-party interest in SCEP as a minority interest in its Consolidated Financial Statements. The total minority interest related to SCEP was $46 million and $49 million as of December 31, 2005 and 2004, respectively. As further discussed in Note 3—Acquisitions and Dispositions, Generation sold its investment in Sithe on January 31, 2005.

In accordance with Financial Accounting Standards Board (FASB) Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities” (FIN No. 46-R), Sithe was consolidated in Generation’s financial statements as of March 31, 2004. See below for further discussion of the adoption of FIN 46-R and the resulting consolidation of Sithe.

Reclassifications

Certain prior year amounts have been reclassified in the financial statements for comparative purposes. The reclassifications did not affect net income.

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

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Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

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 nuclear decommissioning costs and asset retirement obligations, inventory reserves, allowance for doubtful accounts, asset impairments, pension and other postretirement benefits, derivative instruments, fixed asset depreciation, environmental costs, taxes, severance and unbilled energy revenues.

Segment Information

Generation operates as a single reportable segment.

Variable Interest Entities

FIN 46 and its revision FIN 46-R addressed the requirements for consolidating certain variable interest entities. FIN 46 was effective for Generation’s variable interest entities created after January 31, 2003. FIN 46-R was effective December 31, 2003 for Generation’s variable interest entities that were considered to be special-purpose entities and as of March 31, 2004 for all other variable interest entities.

Generation consolidated Sithe, 50% owned through a wholly owned subsidiary of Generation, as of March 31, 2004 pursuant to the provisions of FIN 46-R and recorded income of $32 million (net of income taxes) as a result of the reversal of guarantees of Sithe’s commitments previously recorded by Generation. This income was reported as a cumulative effect of a change in accounting principle in the first quarter of 2004. As of March 31, 2004, Generation was a 50% owner of Sithe, and Generation had accounted for Sithe as an unconsolidated equity method investment prior to March 31, 2004. Sithe owns and operates power-generating facilities and was sold by Generation on January 31, 2005. See Note 3—Acquisitions and Dispositions for additional information regarding the sale of Sithe in 2005.

Revenues

Operating Revenues.Operating revenues are recorded as energy is delivered to customers. At the end of each month, Generation accrues an estimate for the unbilled amount of energy delivered to its customers (see Note 5—Accounts Receivable).

Option Contracts, Swaps, and Commodity Derivatives.Premiums received and paid on option contracts and swap arrangements considered “normal” derivatives pursuant to SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (SFAS No. 133) are amortized to revenue and expensed over the lives of the contracts. Certain option contracts and swap arrangements 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 with unrealized gains and losses recognized in operating revenues.

Trading Activities.Generation accounts for its trading activities under 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 requires revenues and energy costs related to energy trading contracts to be presented on a net basis in the income statement.

367

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Physically Settled Derivative Contracts.Generation accounts for realized gains and losses on physically settled derivative contracts not “held for trading purposes” in accordance with 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).

EITF 03-11 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. Generation adopted EITF 03-11 as of January 1, 2004 and presented purchased power and fuel expense net within revenues of $1,061 million and $38 million, respectively, during 2005, and $966 million and $14 million, respectively, during 2004. Prior periods were not reclassified. The adoption of EITF 03-11 had no effect on Generation’s net income. Had EITF 03-11 been retroactively applied to 2003, operating revenues, purchased power and fuel expense would have been affected as follows:

2003	As Reported		EITF 03-11 Impact			Pro Forma
Operating revenue	$	8,135	$	(996	)	$	7,139
Purchased power		3,587		(943	)		2,644
Fuel expense		1,533		(53	)		1,480

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 benefits carried forward. 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.

Pursuant to the Internal Revenue Code, Exelon files a consolidated Federal income tax return that includes its subsidiaries in which it owns at least 80% of the outstanding stock. Income taxes are allocated to Generation based on the separate return method. Generation records an income tax valuation allowance for deferred tax assets which are not more likely than not to be realized in the future (see Note 12—Income Taxes).

Generation is a party to an agreement (Tax Sharing Agreement) with Exelon 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 Exelon 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. Other comprehensive income primarily relates to unrealized gains and losses on cash-flow hedge instruments and unrealized gains or losses on securities held in nuclear decommissioning trust funds. Comprehensive income is reflected in Generation’s Consolidated Statements of Changes in Membership Interest and Generation’s Consolidated Statements of Comprehensive Income.

368

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

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 and Investments

As of December 31, 2005, restricted cash and investments primarily represented restricted funds for payment of certain environmental liabilities. As of December 31, 2004, restricted cash primarily related to Sithe’s Independence Plant partnership distribution fund. On January 31, 2005, Generation sold its investment in Sithe.

Restricted cash and investments not available for general operations or to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2005, Generation did not have any noncurrent restricted cash and investments. As of December 31, 2004, $93 million of restricted cash and investments were classified within Generation’s deferred debits and other assets, which included $83 million of debt service reserves, major overhaul reserves of $7 million and lease service reserves of $3 million.

Allowance for Doubtful Accounts

The allowance for doubtful accounts reflects Generation’s best estimate of probable losses in the accounts receivable balances. The allowance is based on known troubled accounts, historical experience and other currently available evidence.

Inventories

Inventory is recorded at the lower of cost or market, and provisions are made for excess and obsolete inventory.

Fossil Fuel.Fossil fuel inventory includes the weighted average costs of stored natural gas, coal and oil. The costs of natural gas, coal and oil are generally included in inventory when purchased and charged to fuel expense when used.

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.

Emission Allowances

Emission allowances are included in inventories and other deferred debits and are carried at the lower of weighted average cost or market and charged to fuel expense as they are used in operations. Generation’s emission allowance balances as of December 31, 2005 and 2004 were $112 million and $106 million, respectively.

Marketable Securities

Marketable securities are classified as available-for-sale securities and are reported at fair value pursuant to SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS No. 115). Realized and unrealized gains and losses, net of tax, on nuclear decommissioning trust funds

369

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

transferred to Generation from PECO Energy Company (PECO) and Commonwealth Edison Company (ComEd) are reflected in the payables to affiliates on Generation’s Consolidated Balance Sheets. Realized and unrealized gains and losses on nuclear decommissioning trust funds for the AmerGen units are reported in other comprehensive income. At December 31, 2005 and 2004, Generation had no held-to-maturity securities. See Note 13—Nuclear Decommissioning and Spent Fuel Storage for information regarding marketable securities held by nuclear decommissioning trust funds.

Leases

Generation accounts for leases in accordance with SFAS No. 13, “Accounting for Leases” and determines whether its long-term purchase power and sales contracts are leases pursuant to EITF Issue No. 01-8, “Determining Whether an Arrangement is a Lease” (EITF 01-8). At the inception of the lease, or subsequent modification, Generation determines whether the lease is an operating or capital lease based upon its terms and characteristics. Several of Generation’s long-term purchase power agreements which have been determined to be operating leases have significant contingent rental payments that are dependent on the future operating characteristics of the associated plants such as plant availability. Generation recognizes contingent rental expense when it becomes probable of payment.

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.

Upon retirement, the cost of property is charged to accumulated depreciation.

See Note 6—Property, Plant and Equipment and Note 18—Supplemental Financial Information for additional information regarding property, plant and equipment.

Nuclear Fuel

The cost of nuclear fuel is capitalized and charged to fuel expense using the unit-of-production method. The estimated cost of disposal of Spent Nuclear Fuel (SNF) is established per the Standard Waste Contract with the Department of Energy (DOE) and is expensed at one mill ($.001) per kilowatthour of net nuclear generation. On-site SNF storage costs are capitalized or expensed, as incurred, based upon the nature of the work performed.

Nuclear Outage Costs

Costs associated with nuclear outages are recorded in the period incurred.

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, 2005 and 2004, net unamortized capitalized software costs totaled $31 million and $30 million, respectively. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed ten years. During 2005, 2004 and 2003, Generation amortized capitalized software costs of $11 million, $16 million and $8 million, respectively.

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(Dollars in millions unless otherwise noted)

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, presented by average service life and as a percentage of average service life for electric generating assets, are presented in the tables below.

Average Service Life in Years by Asset Category	2005		2004		2003
Electric—generation	5-62		5-63		5-64
Average Service Life Percentage by Asset Category	2005		2004		2003
Electric—generation	3.59	%	3.34	%	2.90	%

See Note 18- Supplemental Financial Information for further information regarding the amortization of nuclear fuel, asset retirement obligation and intangible assets.

Nuclear Generating Station Decommissioning

Generation accounts for the costs of decommissioning its nuclear generating stations in accordance with SFAS No. 143. See Note 13—Nuclear Decommissioning and Spent Fuel Storage for information regarding the adoption and application of SFAS No. 143.

Capitalized Interest

Generation applies SFAS No. 34, “Capitalizing Interest Costs” to calculate the costs, during the period of construction, of debt funds used to finance its non-regulated construction projects. Generation capitalized interest of $12 million, $11 million and $15 million in 2005, 2004 and 2003, respectively.

Guarantees

Beginning February 1, 2003, pursuant to FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others (FIN 45),” Generation recognizes, at the inception of a guarantee, a liability for the fair market value of the obligations it has undertaken in issuing the guarantee, including the ongoing obligation to perform over the term of the guarantee in the event that the specified triggering events or conditions occur.

The liability that is initially recognized at the inception of the guarantee is reduced as Generation is released from risk under the guarantee. Depending on the nature of the guarantee, Generation’s release from risk may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. The recognition and subsequent adjustment of the liability are highly dependent upon the nature of the associated guarantee.

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

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(Dollars in millions unless otherwise noted)

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 3—Acquisitions and Dispositions for a description of the impairment charge recorded in 2003 related to the long-lived assets of Boston Generating, LLC (Boston Generating).

Upon meeting certain criteria defined in SFAS No. 144, the assets and associated liabilities that compose a disposal group are classified as held for sale and the carrying value of these assets is adjusted downward, if necessary, to the estimated sales price, less cost to sell.

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, 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—Acquisitions and Dispositions for a description of the impairments recorded in 2003 related to Generation’s investment in Sithe and Note 16—Fair Value of Financial Assets and Liabilities for a description of the other-than-temporary impairments in the nuclear decommissioning trust funds determined in 2005 and 2004.

Derivative Financial Instruments

From time to time, Generation enters into derivatives to manage its exposure to fluctuations in interest rates, changes in interest rates related to planned future debt issuances and changes in the fair value of outstanding debt. Generation utilizes derivatives with respect to energy transactions to manage the utilization of its available generating capability and the supply 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. Generation’s derivative activities are in accordance with Exelon’s Risk Management Policy (RMP).

Generation accounts for derivative financial instruments under 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 or normal sales exception. Derivatives on the balance sheet are presented as current or noncurrent mark-to-market derivative assets or liabilities. Changes in the fair value of derivatives are recognized in earnings unless specific hedge accounting criteria are met, in which case those changes are recorded in earnings as an offset to the changes in fair value of the exposure being hedged or deferred in accumulated other comprehensive income and recognized in earnings as hedged transactions occur. Amounts recorded in earnings are included in revenue, purchased power or other, net within Generation’s consolidated statements of income.

Revenues and expenses on contracts that qualify as normal purchases or normal sales are recognized when the underlying physical transaction is completed. “Normal” purchases and 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

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(Dollars in millions unless otherwise noted)

derivative. 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. If it was determined that a transaction designated as a “normal” purchases or a “normal” sale no longer met the scope exceptions, the fair value of the related contract would be recorded on the balance sheet and immediately recognized through earnings.

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, and is designated and qualifies as, a fair-value hedge, are recognized in earnings as offsets to the changes in fair value of the exposure being hedged. Changes in the fair value of a derivative that is highly effective, and is designated and qualifies as, a cash-flow hedge are deferred in accumulated other comprehensive income and are recognized in earnings as the hedged transactions occur. Any ineffectiveness is recognized in earnings immediately. On an ongoing basis, Generation assesses the hedge effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that the derivative is not highly effective as a hedge, hedge accounting will be discontinued prospectively.

Generation enters into contracts to buy and sell energy for trading purposes subject to Exelon’s Risk Management Policy. 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.

Severance Benefits

Generation participates in Exelon’s ongoing severance plans, which are accounted for 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.” Amounts associated with severance benefits that are considered probable and can be reasonably estimated are accrued. See Note 9—Severance Accounting for further discussion of Generation’s accounting for severance benefits.

Retirement Benefits

Generation participates in Exelon’s defined benefit pension plans and postretirement welfare benefit plans in addition to sponsoring a plan. Exelon’s and Generation’s defined benefit pension plans and postretirement welfare benefit plans are accounted for in accordance with SFAS No. 87, “Employer’s Accounting for Pensions” (SFAS No. 87), SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions” (SFAS No. 106) and FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2), and are disclosed in accordance with

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Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

SFAS No. 132-R, “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an Amendment of FASB Statements No. 87, 88, and 106” (revised 2003) (SFAS No. 132-R). See Note 15—Retirement Benefits for further discussion of Generation’s accounting for retirement benefits.

FSP FAS 106-2.Through Exelon’s postretirement benefit plans, Generation provides retirees with prescription drug coverage. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Prescription Drug Act) was enacted on December 8, 2003. 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. Management believes the prescription drug benefit provided under Exelon’s postretirement benefit plans is at least actuarially equivalent to the Medicare prescription drug benefit. In response to the enactment of the Prescription Drug Act, in May 2004, the FASB issued FSP FAS 106-2, which provided transition guidance for accounting for the effects of the Prescription Drug Act and superseded FSP FAS 106-1, which had been issued in January 2004. FSP FAS 106-1 permitted 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. Generation made the one-time election allowed by FSP FAS 106-1 during the first quarter of 2004. During the second quarter of 2004, Generation early adopted the provisions of FSP FAS 106-2, resulting in a reduction in net periodic post retirement benefit cost.

Foreign Currency Translation

The financial statements of Generation’s foreign subsidiaries were prepared in their respective local currencies and translated into U.S. dollars based on the current exchange rates at the end of the periods for the Consolidated Balance Sheets and on weighted-average rates for the periods for Generation’s Consolidated Statements of Income. Foreign currency translation adjustments, net of deferred income tax benefits, are reflected as a component of other comprehensive income on Generation’s Consolidated Statements of Comprehensive Income and, accordingly, have no effect on net income.

New Accounting Pronouncements

EITF 03-1.In March 2004, the EITF reached a consensus on and the FASB ratified EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments” (EITF 03-1). EITF 03-1 provides guidance on recognizing other-than-temporary impairments of investment securities. Generation has adopted the disclosure requirements of EITF 03-1 for investments accounted for under FASB Statement No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS No. 115). On September 30, 2004, the FASB issued FSP EITF 03-1-1, “Effective Date of Paragraphs 10-20 of EITF Issue No. 03-1, ‘The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments,’” which delayed the effective date of the application guidance on impairment of securities included within EITF 03-1. The FASB, at its June 29, 2005 Board meeting, withdrew its guidance on when an impairment is other than temporary. However, EITF 03-1’s provisions regarding the measurement, disclosure and post-impairment accounting guidance of debt securities, as well as the identification of impaired cost method investments remain intact. Additionally, the existing guidance under SFAS No. 115 remains in effect.

SFAS No. 151. In November 2004, the FASB issued FASB Statement No. 151, “Inventory Costs—an amendment of ARB No. 43, Chapter 4” (SFAS No. 151), which is the result of its efforts to

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

converge U.S. accounting standards for inventories with International Accounting Standards. SFAS No. 151 requires abnormal amounts of idle facility expense, freight, handling costs and wasted material or spoilage to be recognized as current-period charges. It also requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS No. 151 will be effective for inventory costs incurred beginning January 1, 2006. The adoption of this standard is not expected to have a material impact on Generation.

SFAS No. 123-R.In December 2004, the FASB issued FASB Statement No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123-R). SFAS No. 123-R replaces SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123) and supersedes Accounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees” (APB No. 25). SFAS No. 123-R requires that compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost will be measured based on the fair value of the equity or liability instruments issued. Exelon will no longer be permitted to follow the intrinsic value accounting method of APB No. 25. APB No. 25 resulted in no expense being recorded for stock option grants for which the strike price was equal to the fair value of the underlying stock on the date of grant, which has been the situation for Exelon for all years prior to 2006. SFAS No. 123-R will be effective for Exelon in the first quarter of 2006 and will apply to all of Exelon’s outstanding unvested share-based payment awards as of January 1, 2006 and all prospective awards using the modified prospective transition method without restatement of prior periods. Exelon will charge a portion of the resulting expense to Generation.

In March 2005, the SEC issued Staff Accounting Bulletin (SAB) No. 107, which expressed the views of the SEC regarding the interaction between SFAS No. 123-R and certain SEC rules and regulations. SAB No. 107 provides guidance related to the valuation of share-based payment arrangements for public companies, including assumptions such as expected volatility and expected term. See Note 1—Significant Accounting Policies of Exelon’s Notes to Consolidated Financial Statements for further information regarding the estimated impact of Exelon’s adoption of SFAS 123-R.

Generation participates in Exelon’s stock-based compensation plans. Exelon accounts for its stock-based compensation plans under the intrinsic method prescribed by APB No. 25 and related interpretations and follows the disclosure requirements of SFAS No. 123 and SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123.” Accordingly, compensation expense related to stock options recognized within Generation’s Consolidated Statements of Income was insignificant in 2005, 2004 and 2003. The tables below show the effect on Generation’s net income for 2005, 2004 and 2003 had Exelon elected to account for all of its stock-based compensation plans using the fair-value method under SFAS No. 123:

	2005		2004		2003
Net income (loss)—as reported	$	1,098	$	673	$	(133	)
Deduct: Total stock-based compensation expense under fair-value method for all awards, net of income taxes(a)		7		12		11
Pro forma net income (loss)	$	1,091	$	661	$	(144	)

(a) The fair value of options granted was estimated using a Black-Scholes-Merton option pricing model.

SFAS No. 153. In December 2004, the FASB issued FASB Statement No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, ‘Accounting for Nonmonetary Transactions’” (SFAS No. 153). Previously, APB Opinion No. 29 had required that the accounting for an exchange of a productive asset for a similar productive asset or an equivalent interest in the same

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(Dollars in millions unless otherwise noted)

or similar productive asset should be based on the recorded amount of the asset relinquished. The amendments made by SFAS No. 153 are based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, the amendments eliminate the narrow exception for nonmonetary exchanges of similar productive assets and replace it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance, in essence increasing the number of exchanges that will be fair valued in the future. SFAS No. 153 was effective in the third quarter of 2005. The provisions of SFAS No. 153 are applied prospectively. The adoption of this standard did not have a material impact to Generation’s financial condition or results of operations in the third or fourth quarter of 2005.

FIN 47. In March 2005, the FASB issued FIN 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47) which clarifies that the term “conditional asset retirement obligation” as used in FASB Statement No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143), refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 requires an entity to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 was effective for Generation as of December 31, 2005. See Note 14—Conditional Asset Retirement Obligations for further information.

SFAS No. 154. In May 2005, the FASB issued FASB Statement No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS No. 154). Previously, APB No. 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements” required the inclusion of the cumulative effect of changes in accounting principle in net income of the period of the change. SFAS No. 154 requires companies to recognize a change in accounting principle, including a change required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements. Generation will assess the impact of a retrospective application of a change in accounting principle in accordance with SFAS No. 154 when such a change arises after the effective date of January 1, 2006.

Cumulative Effect of Changes in Accounting Principles

FIN 47.During 2005, Generation recorded a charge of $30 million (net of income taxes of $19 million) as a cumulative effect of a change in accounting principle pursuant to the adoption of FIN 47. See discussion of the adoption of FIN 47 above.

FIN 46-R.See discussion of the adoption of FIN 46-R within the “Variable Interest Entities” discussion above.

SFAS No. 143.SFAS No. 143 provides accounting guidance 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 and 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 components of the cumulative effect of a change in accounting principle, net of income taxes, were as follows:

Generation (net of income taxes of $52)	$	80
Generation’s investments in AmerGen and Sithe (net of income taxes of $18)		28
Total	$	108

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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

The following tables set forth Generation’s net income for the years ended December 31, 2005, 2004 and 2003, adjusted as if SFAS No. 143, FIN 46-R and FIN 47 had been applied during those periods. SFAS No. 143, FIN 46-R and FIN 47 had adoption dates of January 1, 2003, March 31, 2004 and December 31, 2005, respectively.

	2005			2004			2003
Reported income (loss) before cumulative effect of changes in accounting principles	$	1,128		$	641		$	(241	)
Pro forma earnings effects (net of income taxes):
FIN 47		(4	)		(4	)		(4	)
FIN 46-R		—			—			32
Pro forma income (loss) before cumulative effect of changes in accounting principles	$	1,124		$	637		$	(213	)
Reported net income (loss)	$	1,098		$	673		$	(133	)
Pro forma earnings effects (net of income taxes):
FIN 47		(4	)		(4	)		(4	)
FIN 46-R		—			—			32
Reported cumulative effects of changes in accounting principles:
FIN 47		30			—			—
FIN 46-R		—			(32	)		—
SFAS No. 143		—			—			(108	)
Pro forma net income (loss)	$	1,124		$	637		$	(213	)

2. Discontinued Operations

On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. In addition, during 2004, Generation sold or wound down substantially all components of AllEnergy Gas & Electric Marketing LLC (AllEnergy), a business within Exelon Energy. As a result, the results of operations and any gain or loss on the sale of these entities are presented as discontinued operations in 2005 within Generation’s Consolidated Statements of Income. In addition, the results of operations of these entities have been presented as discontinued operations in 2004 for comparative purposes. Results related to these entities were as follows:

2005	Sithe (a)		AllEnergy		Total
Total operating revenues	$	30	$	—	$	30
Operating income		5		1		6
Income before income taxes and minority interest		23		1		24

(a) Sithe was sold on January 31, 2005. Accordingly, results include only one month of operations. See Note 3—Acquisitions and Dispositions for further information regarding the sale of Sithe.

2004	Sithe (a)			AllEnergy			Total
Total operating revenues	$	227		$	8		$	235
Operating loss		(7	)		(2	)		(9	)
Loss before income taxes and minority interest		(58	)		(2	)		(60	)

(a) Includes Sithe’s results of operations from April 1, 2004 through December 31, 2004. See Note 3—Acquisitions and Dispositions for further information regarding the sale of Sithe.

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(Dollars in millions unless otherwise noted)

As discussed in Note 3—Acquisitions and Dispositions, Generation sold its indirect wholly owned subsidiary Boston Generating in 2004. Because Generation maintains significant continuing involvement with this entity, due to various contractual arrangements described in Note 3—Acquisitions and Dispositions, it has not been classified as discontinued operations within Generation’s Consolidated Statements of Income.

3. Acquisitions and Dispositions

Acquisition and Disposition of Sithe

Sithe is primarily engaged in the ownership and operation of electric wholesale generating facilities in North America. At December 31, 2004, Sithe operated nine power units with total average net capacity of 1,323 MWs. Described below is a series of transactions in 2004 and 2003 involving Generation’s investment in Sithe that ultimately resulted in the sale of Generation’s ownership interest in Sithe to a third party on January 31, 2005.

On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. Specifically, subsidiaries of Generation closed on the acquisition of Reservoir Capital Group’s (Reservoir) 50% interest in Sithe and the sale of 100% of Sithe to Dynegy, Inc. (Dynegy). Prior to closing on the sale to Dynegy, subsidiaries of Generation received approximately $65 million in cash distributions from Sithe. As a result of the sale, Generation deconsolidated approximately $820 million of debt from its balance sheets and was no longer required to provide $125 million of credit support to Dynegy on behalf of Sithe. Dynegy acquired $32 million of cash as part of the sale of Sithe. Additionally, Generation recorded $55 million of liabilities related to certain indemnifications provided to Dynegy and other guarantees directly resulting from the transaction. These liabilities were taken into account in the determination of the net gain on the sale of $24 million (before income taxes). As of December 31, 2005, Generation’s accrued liabilities related with these indemnifications and guarantees were $46 million. The net decrease was a result of the unwinding of certain guarantees and tax indemnifications that were associated with the sale transaction.

Generation issued certain guarantees associated with income tax indemnifications to Dynegy in connection with the sale that were valued at approximately $8 million, of which $3 million has been unwound as of December 31, 2005. These guarantees are being accounted for under the provisions of FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others” (FIN 45). The exposures covered by these indemnities are anticipated to expire in 2006 and beyond. The estimated maximum possible exposure to Generation related to the guarantees provided as part of the sales transaction to Dynegy is approximately $175 million at December 31, 2005.

Generation’s Consolidated Statements of Income included the following financial results related to Sithe:

	2005 (a)		2004 (b)
Operating revenues	$	30	$	248
Operating income		5		1
Net income (loss) (c)		18		(27	)

(a) Sithe was sold on January 31, 2005. Accordingly, results include only one month of operations.

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(Dollars in millions unless otherwise noted)

(b) Results include Generation’s equity-method losses from Sithe prior to its consolidation on March 31, 2004, as well as transmission congestion contract (TCC) revenues for 2004, and are not included in the discontinued operations of Sithe (see Note 2—Discontinued Operations for further information regarding the disposal of Sithe). These equity-method losses and TCC revenues are presented within income from continuing operations on Generation’s Consolidated Statements of Income.

(c) Net income for 2005 included a pre-tax gain on sale of Sithe of $24 million.

Generation’s Consolidated Balance Sheets as of December 31, 2004 included current assets, noncurrent assets, current liabilities and noncurrent liabilities, which were disposed of upon the sale of Sithe on January 31, 2005, of $57 million, $885 million, $106 million and $825 million, respectively.

Exercise of Call Option and Subsequent Agreement to Sell.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 (Generation owned 49.9% prior to November 25, 2003). See below for further details regarding these 2003 transactions.

Both Generation’s and Reservoir’s 50% interests in Sithe were subject to put and call options. On September 29, 2004, Generation exercised its call option and entered into an agreement to acquire Reservoir’s 50% interest in Sithe for $97 million. On November 1, 2004, Generation entered into an agreement to sell Sithe to Dynegy for $135 million in cash. On January 31, 2005, Generation completed the closing of the call exercise and the sale of the resulting 100% interest in Sithe. The sale did not include Sithe International, Inc., which was sold to a subsidiary of Generation in a separate transaction described below.

Acquisition of Sithe International, Inc.Sithe International, Inc., through its subsidiaries, has 49.5% interests in two Mexican business trusts that own the TEG and TEP power stations, two 230 MW petcoke-fired generating facilities in Tamuín, Mexico that commenced commercial operations in the second quarter of 2004. On October 13, 2004, Sithe transferred all of the shares of Sithe International, Inc. and its subsidiaries to a subsidiary of Generation in exchange for cancellation of a $92 million note, which is eliminated as part of the consolidation of Sithe. Effective January 26, 2005, Sithe International Inc.’s name was changed to Tamuin International Inc.

2003 Transactions. 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. 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 49.9% interest on November 24, 2003 and the remaining 50.1% interest on May 27, 2004 for separate consideration) for $178 million.

Following the sales of the above entities, Generation transferred its wholly owned subsidiary that held the Sithe investment to a newly formed holding company, EXRES SHC, Inc. 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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Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Guarantees.In connection with the 2003 transactions, Generation recorded obligations related to $39 million of guarantees in accordance with FIN 45. These guarantees were issued to protect Reservoir from credit exposure of certain counterparties 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. These guarantees were reversed upon the consolidation of Sithe in accordance with FIN 45 as this liability was associated with guarantees for the performance of a consolidated entity. The consolidation of Sithe in accordance with FIN 46-R resulted in Generation recording income of $32 million (net of income taxes), which included the reversal of the aforementioned guarantees, as a cumulative effect of a change in accounting principle during the first quarter of 2004.

Accounting Prior to the Consolidation of Sithe on March 31, 2004.Generation had accounted for the investment in Sithe as an unconsolidated equity method investment prior to its consolidation on March 31, 2004 pursuant to FIN 46-R. See Note 1—Significant Accounting Policies for further discussion. In 2003, Generation recorded impairment charges of $255 million (before income taxes) in other income and deductions within Generation’s 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.

The book value of Generation’s investment in Sithe immediately prior to its consolidation on March 31, 2004 was $49 million. For the year ended December 31, 2004, Exelon recorded $2 million of equity method losses from Sithe prior to its consolidation. For the year ended December 31, 2003 and 2002, Generation recorded $2 million and $23 million of equity method income, respectively, related to its investment in Sithe.

Consolidation of Sithe as of March 31, 2004.As a result of the 2003 transactions referred to above, the consolidation of Sithe at March 31, 2004 was accounted for as a step acquisition pursuant to purchase accounting policies. Under the provisions of FIN 46-R, the operating results of Sithe were included in Generation’s results of operations beginning April 1, 2004.

Intangible Assets.Sithe had entered into a tolling arrangement (Tolling Agreement) with Dynegy Power Marketing and its affiliates with respect to Sithe’s Independence Station. The Tolling Agreement commenced on July 1, 2001 and runs through 2014. Additionally, Sithe entered into an energy purchase agreement (Energy Purchase Agreement) with a counterparty relating to the Independence Station, which continues through 2014. As a result of the acquisition accounting described above, values were assigned to the Tolling Agreement and the Energy Purchase Agreement of approximately $73 million and $384 million, respectively, which were recorded as intangible assets on Generation’s Consolidated Balance Sheets in deferred debits and other assets. These amounts were determined based on fair value techniques utilizing the contract terms and various other estimates including forward power prices, discount rates and option pricing models.

Prior to the sale of Sithe, the intangible assets representing the Tolling Agreement and the Energy Purchase Agreement were being amortized on a straight-line basis over the lives of the associated agreements. See Note 8—Intangible Assets for further information regarding Generation’s intangible assets.

380

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Long-Term Debt and Letters of Credit.Substantially all of Sithe’s property, plant and equipment and project agreements secured Sithe’s outstanding long-term debt, which consisted primarily of project debt. During 2003, Sithe entered into an agreement with Generation under which Exelon obtained letters of credit to support contractual obligations of Sithe and its subsidiaries. As of December 31, 2004, Exelon had obtained $111 million of letters of credit in support of Sithe’s obligations. As a result of the sale of Sithe on January 31, 2005, Generation was no longer required to provide credit support, which included letters of credit.

Sale of Ownership Interest in Boston Generating, LLC

On May 25, 2004, Generation completed the sale, transfer and assignment of ownership of its indirect wholly owned subsidiary Boston Generating, which owns the companies that own Mystic 4-7, Mystic 8 and 9 and Fore River generating facilities, to a special purpose entity owned by the lenders under Boston Generating’s $1.25 billion credit facility (Boston Generating Credit Facility).

The sale was pursuant to a settlement agreement reached with Boston Generating’s lenders on February 23, 2004. The Federal Energy Regulatory Commission (FERC) approved the sale of Boston Generating on May 25, 2004. Responsibility for plant operations and power marketing activities were transferred to the lenders’ special purpose entity on September 1, 2004.

In connection with the settlement reached on February 23, 2004, Exelon, Generation, the lenders and Raytheon Company (Raytheon), the guarantor of the obligations of the turnkey contractor under the projects’ engineering, procurement and construction agreements, entered into a global settlement of all disputes relating to the construction of the Mystic 8 and 9 and Fore River generating facilities.

In connection with the decision to transition out of Boston Generating and the generating units, Generation recorded during the third quarter of 2003 an impairment charge of long-lived assets pursuant to SFAS No. 144 of $945 million ($573 million net of income taxes) in operating expenses within its Consolidated Statements of Income. At the date of the sale, Boston Generating had approximately $1.2 billion in assets, primarily consisting of property, plant and equipment, and approximately $1.3 billion of liabilities of which approximately $1.0 billion was debt outstanding under the Boston Generating Credit Facility. As of the date of transfer, these amounts were eliminated from Generation’s Consolidated Balance Sheets. As a result of Boston Generating’s liabilities being greater than its assets at the time of the sale, transfer and assignment of ownership, Generation recorded a gain of $85 million ($52 million net of income taxes) in other income and deductions within Generation’s Consolidated Statements of Income in the second quarter of 2004.

In connection with the sale, Generation recorded a liability associated with an existing guarantee by its subsidiary Exelon New England Holdings, LLC (Exelon New England) of fuel purchase obligations of Boston Generating. At December 31, 2005, the liability associated with this guarantee was $14 million. Due to the existence of this guarantee and in accordance with SFAS No. 144 and EITF 03-13, Generation determined that it had retained risk and continuing involvement associated with the operations of Boston Generating and, as a result, the results of Boston Generating have not been classified as a discontinued operation within Generation’s Consolidated Statements of Income. See Note 17—Commitments and Contingencies for further information regarding the guarantee.

381

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Generation’s Consolidated Statements of Income include the following results related to Boston Generating:

	2004			2003
Operating revenues	$	248		$	618
Operating loss (a)		(49	)		(954	)
Income (loss) (b)		21			(583	)

(a) The operating loss in 2003 included an impairment loss of $945 million ($573 million net of income taxes) related to Boston Generating’s long-lived assets.

(b) Net income for 2004 included an after-tax gain of $52 million related to the sale of Boston Generating in the second quarter of 2004.

Acquisition of AmerGen Energy Company, LLC

On December 22, 2003, Generation purchased British Energy plc’s (British Energy) 50% interest in AmerGen Energy Company, LLC (AmerGen). The resolution of purchase price contingencies related to the valuation of long-lived assets was finalized during the fourth quarter of 2004, reflecting the final purchase price of $267 million after working capital adjustments.

Prior to the purchase, Generation was a 50% owner of AmerGen and had accounted for the investment as an unconsolidated equity method investment. From January 1, 2003 through the date of closing, Generation recorded $47 million ($28 million, net of tax) of equity in earnings of unconsolidated affiliates related to its investment in AmerGen and recorded $382 million of purchased power from AmerGen. The book value of Generation’s investment in AmerGen prior to the purchase was $316 million.

In connection with the purchase of Unit No. 1 of the Three Mile Island (TMI) facility by AmerGen in 2000, AmerGen entered into an agreement with the seller whereby the seller would receive additional consideration based upon future purchase power prices through 2009. Under the terms of the agreement, approximately $11 million and $7 million had been accrued at December 31, 2005 and 2004, respectively. The amount accrued as of December 31, 2005 will be payable to the former owners of the TMI facility in the first quarter of 2006 and the amount accrued as of December 31, 2004 was paid in the first quarter of 2005. These payments represented contingent consideration for the original acquisition and have accordingly been reflected as increases to the long-lived assets associated with the TMI facility, and are being depreciated over the remaining useful life of the facility.

Exelon Energy Company

Effective January 1, 2004, Exelon contributed its interest in Exelon Energy to Generation. The transaction had no effect on the assets and liabilities of Exelon Energy, which were previously reported as a part of Enterprises in Exelon’s financial statements only. Beginning in 2004, Exelon Energy’s assets and liabilities and results of operations are included in Generation’s financial statements.

382

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

The following summary represents the assets and liabilities of Exelon Energy that were transferred to Generation at book value as of January 1, 2004:

Current assets (including $5 million of cash)	$	119
Property, plant and equipment		2
Deferred debits and other assets		13
Total assets	$	134
Current liabilities		126
Deferred credits and other liabilities		10
Member’s equity		(2	)
Total liabilities and member’s equity	$	134

Selected Pro Forma and Consolidating Financial Information (Unaudited)

The following unaudited pro forma financial information gives effect to the acquisition on December 22, 2003 of the remaining 50% interest in AmerGen by Generation, the transfer of Exelon Energy to Generation on January 1, 2004 and the sale of Boston Generating by Generation on May 25, 2004, in each case, as if the transaction had occurred on January 1, 2003.

2004	Generation As Reported		Sale of Boston Generating			Eliminating Entries		Pro Forma Generation
Total operating revenues	$	7,703	$	248		$	—	$	7,455
Operating income (loss)		1,039		(49	)		—		1,088
Income from continuing operations		657		21			—		636

2003	Generation As Reported			Businesses Acquired (a)		Sale of Boston Generating			Eliminating Entries (b)			Pro Forma Generation
Total operating revenue	$	8,135		$	1,283	$	618		$	(591	)	$	8,209
Operating income (loss)		(115	)		111		(954	)		—			950
Income (loss) from continuing operations		(241	)		71		(583	)		(47	)		366

(a) Consists of the acquisition of the remaining 50% interest in AmerGen and the transfer of Exelon Energy to Generation.

(b) Represents the elimination of intercompany revenues at AmerGen and Exelon Energy and equity in earnings from AmerGen in 2003.

The above unaudited pro-forma financial information should not be relied upon as being indicative of the historical results that would have been obtained if the transactions had actually occurred in prior periods nor of the results that might be obtained in the future.

383

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Condensed Consolidating Balance Sheet at December 31, 2004 (Unaudited)

The following condensed consolidating financial information presents the financial position of Generation, Sithe and Exelon Energy, as well as eliminating entries, related primarily to acquisition notes payable and receivables between Generation and Sithe.

December 31, 2004	Pro Forma		Sithe		Exelon Energy		Eliminating Entries			Consolidated (As Reported)
Assets
Current assets	$	2,238	$	336	$	128	$	(381	)	$	2,321
Property, plant and equipment, net		7,265		270		1		—			7,536
Other noncurrent assets		5,849		750		13		(31	)		6,581
Total assets	$	15,352	$	1,356	$	142	$	(412	)	$	16,438
Liabilities and member’s equity
Current liabilities	$	2,348	$	323	$	126	$	(381	)	$	2,416
Long-term debt		1,798		785		—		—			2,583
Other long-term liabilities (a)		8,180		181		3		36			8,400
Member’s equity		3,026		67		13		(67	)		3,039
Total liabilities and member’s equity	$	15,352	$	1,356	$	142	$	(412	)	$	16,438

(a) Includes minority interest of consolidated subsidiaries.

4. Regulatory Issues

Market-Based Rates Filing.On July 5, 2005, the FERC approved Generation’s continued authority to charge market-based rates for wholesale sales of electricity, including to its affiliates ComEd and PECO. In the same order, the FERC stated that Generation had failed to address the affiliate abuse prong of the FERC’s market-based rate eligibility test and used that statement as the basis for instituting a proceeding under the provision of the Federal Power Act, section 206 and establishing a refund effective date of July 26, 2005 in the event that the FERC ultimately found that Generation did not, in fact, qualify for market-based rates. The FERC ordered Exelon to make a compliance filing within 30 days of the order addressing the affiliate abuse and reciprocal dealing prong of the market-based rate test.

On August 4, 2005, Generation filed a Petition for Rehearing asking the FERC to rescind the part of its market-based rate order that had opened a section 206 investigation into the issue of affiliate abuse and established a refund effective date. Generation had addressed the affiliate abuse issue in its original November 2003 triennial update filing. The September 2004 filing had addressed only the new generation market power issue, as the FERC had directed. In the August 2005 filing, Generation noted the original reference in the September 2004 filing to the fact that FERC had previously found that circumstances existed that guarded against affiliate abuse. Generation further noted that as of both the September 2004 and August 2005 filings there had been no change in the circumstances cited in FERC’s original order granting authority to Generation to sell electricity at market-based rates. Generation’s pleading asks the FERC to either grant the rehearing request or consider the August 2005 filing to be the required compliance filing.

384

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

The July 2005 market-based rate order also directed Exelon to make compliance filings within 30 days of the order amending the market-based rate tariffs of Exelon’s various subsidiaries to include prohibiting sales of electricity to Public Service Electric and Gas Company (PSE&G), Public Service Enterprise Group Incorporated’s (PSEG) regulated utility, unless specific authority were sought for such sales under Section 203 of the Federal Power Act. These compliance filings were made in accordance with the order.

Exelon expects the FERC to make a decision in 2006. If the FERC were to suspend Generation’s market-based rate authority, Generation would be required to supply and implement a plan for mitigation of market power. FERC’s default mitigation would require Generation 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.

Service Life Extension.Upon the December 2003 acquisition of the remaining 50% interest in AmerGen, Generation changed its accounting estimates related to the depreciation of certain AmerGen generating facilities to conform with Generation’s depreciation policies. The estimated service lives were extended by 20 years for the three AmerGen stations. These changes were based on engineering and economic feasibility analyses performed by Generation. The service life extensions are subject to approval by the Nuclear Regulatory Commission (NRC) of renewals of the existing NRC operating licenses. In the first quarter of 2005, Generation applied the same depreciation estimated useful life assumption to its ownership share in the Salem Generating Station.

License Renewals. In December 2004, the NRC issued an order that will permit the Oyster Creek Generating Station (Oyster Creek) to operate beyond its license expiration in April 2009 if the NRC has not completed reviewing the application for renewal. In July 2005, Generation applied for license renewal for Oyster Creek and is planning on filing for license renewals for TMI Unit 1 and the Clinton Nuclear Power Station (Clinton) on a timeline consistent and integrated with the other planned license renewal filings for the Generation nuclear fleet. On October 28, 2004, the NRC approved 20-year renewals of the operating licenses for Generation’s Dresden and Quad Cities generating stations. The licenses for Dresden Unit 2, Dresden Unit 3 and Quad Cities Units 1 and 2 were renewed to 2029, 2031 and 2032, respectively. On May 7, 2003, the operating licenses for Peach Bottom Unit 2 and Peach Bottom Unit 3 were renewed to 2033 and 2034, respectively. Depreciation provisions are based on the estimated useful lives of the stations, which assumes the renewal of the licenses for all nuclear generating stations. As a result, these license renewals had no impact on Generation’s Consolidated Statements of Income.

The Energy Policy Act of 2005. The Energy Policy Act of 2005 (the Energy Policy Act), which was signed into law on August 8, 2005, implements several significant changes intended to improve electric reliability, promote investment in electric facilities, streamline electric regulation, improve wholesale competition, address problems identified in the Western energy crisis and Enron collapse, promote fuel diversity and cleaner fuel sources, and promote greater efficiency in electric generation, delivery and use.

The Energy Policy Act also transfers to FERC certain additional authority. FERC obtains new authority to review the acquisition or merger of generating facilities, along with the responsibility to address more explicitly cross-subsidization issues in these situations. FERC now has the authority to approve siting of electric transmission facilities located in national interest electric transmission corridors if states cannot or will not act in a timely manner to approve siting. The Energy Policy Act also creates a self-regulating electric reliability organization with FERC oversight to enforce reliability rules.

385

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

In addition, the Energy Policy Act extends the Price-Anderson Act to December 31, 2025. See Note 17—Commitments and Contingencies for further discussion of the Price-Anderson Act.

Additionally, the Energy Policy Act repealed PUHCA effective February 8, 2006. Since Exelon was a registered holding company under PUHCA, Exelon and its subsidiaries, including Generation, were subject to a number of restrictions. These restrictions involved financings, investments and affiliate transactions. Exelon had an order under PUHCA authorizing financing transactions within certain limits. Exelon also had an order under PUHCA authorizing development activities, the formation of new intermediate subsidiaries for internal corporate structuring, internal corporate reorganizations, and investments in certain non-U.S. energy-related subsidiaries. PUHCA also limited the businesses in which Exelon could engage in and the investments that Exelon could make, and required that Exelon’s utility subsidiaries constituted a single system that could be operated in an efficient, coordinated manner. With the repeal of PUHCA, Exelon will no longer be subject to these restrictions. However, Section 203 of the Federal Power Act as amended by the Energy Policy Act, and regulations promulgated thereunder, governs intercompany system financings and cash management arrangements, certain internal corporate reorganizations, and certain holding company acquisitions of public utility and holding company securities. FERC obtained additional jurisdiction for the review of affiliate transactions, and FERC’s financing jurisdiction resumes to the extent that it was preempted by PUHCA.

With the repeal of PUHCA, the SEC’s financing jurisdiction under PUHCA for Generation’s financings reverted to FERC. Generation currently has blanket financing authority that it received from FERC in November 2000 that became effective again with the repeal of PUHCA. If the FERC proceeding relating to Generation’s market-based rate authority results in revocation of that authority, Generation’s blanket financing authority may also be revoked. If that financing authority is revoked, it is possible that the revocation of financing authority would be effective prospectively. It is also possible that the revocation of financing authority might be retroactive to October 2, 2005. FERC has adopted regulations that would grandfather prior SEC approvals of financings at a company’s election. The FERC regulations require that companies intending to issue securities in reliance on their SEC financing orders file with FERC a copy of their SEC financing order within 30 days after the effective date of PUHCA repeal. In light of the potential uncertainty relating to the possible revocation of FERC’s blanket financing authority, Exelon has filed its SEC financing order with the FERC. The SEC financing order contains certain terms, limits, and reporting requirements which Exelon continues to review to determine the extent to which it would be subject to such conditions.

To the extent that the SEC’s jurisdiction under PUHCA preempted certain aspects of state regulation of Exelon, the repeal of PUHCA will permit the states in which Exelon and its subsidiaries, including Generation, operate to adopt additional regulations if they so choose, absent any preemption by the FERC.

5. Accounts Receivable

Customer accounts receivable at December 31, 2005 and 2004 included estimated unbilled revenues, representing an estimate for the unbilled amount of energy or services provided to customers, and allowance for uncollectible accounts as follows:

	2005		2004
Unbilled revenues	$	524	$	449
Allowance for uncollectible accounts		15		19

386

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

6. Property, Plant and Equipment

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2005 and 2004:

	December 31,
Asset Category	2005		2004
Electric—generation	$	7,286	$	7,125
Nuclear fuel		3,148		2,926
Construction work in progress		494		357
Asset retirement cost(a)		797		1,023
Other property, plant and equipment(b)		54		54
Total property, plant and equipment		11,779		11,485
Less accumulated depreciation(c)		4,315		3,949
Property, plant and equipment, net	$	7,464	$	7,536

(a) See Note 13—Nuclear Decommissioning and Spent Fuel and Note 14—Conditional ARO for further information.

(b) Includes buildings under capital lease with a net carrying value of $40 million and $43 million at December 31, 2005 and December 31, 2004, respectively. The original cost basis of the buildings was $53 million and total accumulated amortization was $13 million and $10 million at December 31, 2005 and December 31, 2004, respectively.

(c) Includes accumulated amortization of nuclear fuel of $2,103 million and $1,976 million at December 31, 2005 and December 31, 2004, respectively.

Service Life Extensions.Upon the December 2003 acquisition of the remaining 50% interest in AmerGen, Generation changed its accounting estimates related to the depreciation of certain AmerGen generating facilities to conform with Generation’s depreciation policies. See Note 4—Regulatory Issues for further information on service life extensions.

License Renewals. Depreciation provisions are based on the estimated useful lives of the stations, which assumes the renewal of the licenses for all nuclear generating stations. As a result, the receipt of license renewals has no impact on Generation’s Consolidated Statements of Income. See Note 4—Regulatory Issues for further information on license renewals.

387

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

7. Jointly Owned Electric Utility Plant

Generation’s undivided ownership interests in jointly owned electric plant at December 31, 2005 and 2004 were as follows:

	Nuclear generation						Fossil fuel generation
	Quad Cities		Peach Bottom		Salem (a)		Keystone		Conemaugh		Wyman
Operator	Generation		Generation		PSEG Nuclear		Reliant		Reliant		FP&L
Ownership interest		75.00%		50.00%		42.59%		20.99%		20.72%		5.89%
Generation’s share at December 31, 2005:(b)
Plant	$	363	$	449	$	181	$	171	$	217	$	2
Accumulated depreciation		67		241		42		107		138		1
Construction work in progress		51		22		78		5		1		—
Generation’s share at December 31, 2004:(b)
Plant	$	287	$	438	$	127	$	167	$	212	$	2
Accumulated depreciation		54		231		33		102		133		—
Construction work in progress		39		16		81		5		1		—

(a) Generation also owns a proportionate share in the fossil fuel combustion turbine, which is fully depreciated. The gross book value was $3 million at December 31, 2005 and 2004.

(b) Generation has a 44.24% ownership interest in Merrill Creek Reservoir located in New Jersey with a book value of $1 million at December 31, 2005 and 2004.

Generation’s undivided ownership interests are financed with its funds and all operations are accounted for as if such participating interests were wholly owned facilities. Generation’s share of direct expenses of the jointly owned plants are included in the corresponding operating expenses on Generation’s Consolidated Statements of Income.

8. Intangible Assets

Generation’s intangible assets, included in deferred debits and other assets, consisted of the following:

	December 31, 2005						December 31, 2004
	Gross		Accumulated Amortization		Net		Gross		Accumulated Amortization			Net
Amortized intangible assets:
Energy purchase agreement (a)	$	—	$	—	$	—	$	384	$	(27	)	$	357
Tolling agreement(a)		—		—		—		73		(5	)		68
Other		—		—		—		6		(6	)		—
Total intangible assets		—		—		—	$	463	$	(38	)	$	425

(a) These intangible assets were eliminated from the Consolidated Balance Sheets of Generation upon the sale of Sithe on January 31, 2005. See Note 3 – Acquisitions and Dispositions for further information regarding the sale of Sithe.

For the year ended December 31, 2005, Generation’s amortization expense related to intangible assets was $4 million, which has been reflected as a reduction in revenues related to the energy

388

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

purchase agreement and the tolling agreement. For the year ended December 31, 2004, Generation’s amortization expense related to intangible assets was $38 million, of which $32 million has been reflected as a reduction in revenues related to the energy purchase agreement and the tolling agreement. Generation’s amortization expense was not significant in 2003. Generation sold Sithe on January 31, 2005, which resulted in the elimination of the intangible assets related to Sithe’s energy purchase agreement and tolling agreement from Generation’s Consolidated Balance Sheets. See Note 3—Acquisitions and Dispositions for further information regarding this sale.

9. Severance Accounting

Generation 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 compensation level. Generation accounts for its ongoing severance plans in accordance with SFAS No. 112 and SFAS No. 88 and accrues amounts associated with severance benefits that are considered probable and that can be reasonably estimated.

The following tables present total salary continuance severance costs (benefits), recorded as an operating and maintenance expense, during 2005, 2004 and 2003:

Salary Continuance Severance
Income recorded—2005(a) (b)	$	(4	)
Expense recorded—2004		2
Expense recorded—2003		38

(a) Represents reduction in previously recorded severance reserves.

(b) Excludes severance charges of $5 million related to Salem, of which Generation owns 42.59% and which is operated by PSEG Nuclear, LLC (PSEG Nuclear).

The following table provides a roll forward of the salary continuance severance obligations from January 1, 2004 through December 31, 2005:

Salary Continuance Obligations
Balance at January 1, 2004	$	43
Severance charges recorded		2
Cash payments		(29	)
Balance at January 1, 2005	$	16
Reduction in obligation estimate(a)		(4	)
Cash payments		(5	)
Balance at December 31, 2005	$	7

(a) Excludes severance charges of $5 million related to Salem, of which Generation owns 42.59% and which is operated by PSEG Nuclear.

389

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

10. Short-Term Debt

	2005			2004			2003
Average borrowings	$	26		$	72		$	—
Maximum borrowings outstanding		317			326			—
Average interest rates, computed on a daily basis		4.12	%		1.14	%		—
Average interest rates, at December 31		4.67	%		—			—

At December 31, 2003, Exelon, along with ComEd, PECO and Generation, participated with a group of banks in a $750 million 364-day unsecured revolving credit agreement and a $750 million three-year unsecured revolving credit agreement. On July 16, 2004, the $750 million 364-day facility was replaced with a $1 billion unsecured revolving facility maturing on July 16, 2009, and the $750 million three-year facility was reduced to $500 million maturing on October 31, 2006. 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.

At December 31, 2005, Generation had the following sublimits and available capacity under the credit agreements and the indicated amounts of outstanding commercial paper:

Borrower	Bank Sublimit (a)		Available Capacity (b)		Outstanding Commercial Paper
Generation	$	400	$	353	$	311

(a) Sublimits under the credit agreements can change upon written notification to the bank group.

(b) Available capacity represents the bank sublimit net of outstanding letters of credit. The amount of commercial paper outstanding does not reduce the available capacity under the credit facilities.

The credit agreements require Generation to maintain a minimum 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 attributable to certain changes in working capital. For the twelve months ended December 31, 2005, Generation’s minimum cash from operations to interest expense ratio was 3.25 to 1. At December 31, 2005, Generation was in compliance with this threshold.

On February 10 through 13, 2006, Generation entered into separate additional credit facilities with aggregate bank commitments of $875 million. See Note 21—Subsequent Events for further information.

390

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

11. Long-Term Debt

				December 31,
	Rates		Maturity Date	2005			2004
Long-term debt
Senior unsecured notes	5.35	%-6.95%	2011-2014	$	1,200		$	1,200
Pollution control notes, floating rates	3.03	%-3.55%	2016-2034		520			520
Notes payable and other(a)	6.33	%-7.83%	2006-2020		85			99
Sithe long-term debt(b)
Non-recourse secured project debt
Independence	8.50	%-9.00%	2007-2013		—			499
Batavia		18.00%	2007		—			1
Subordinated debt		7.00%	2034		—			419
Total long-term debt(c)					1,805			2,738
Unamortized debt discount and premium, net					(5	)		(108	)
Due within one year					(12	)		(47	)
Long-term debt				$	1,788		$	2,583

(a) Includes Generation’s capital lease obligations of $46 million and $50 million at December 31, 2005 and 2004, respectively. Generation will make lease payments of $2 million, $2 million, $2 million, $2 million, $2 million and $36 million in 2006, 2007, 2008, 2009, 2010 and thereafter, respectively.

(b) These amounts were removed from Generation’s consolidated balance sheets following Generation’s sale of Sithe, which was completed on January 31, 2005. See Note 3—Acquisitions and Dispositions for further information. Prior to the sale, in addition to the stated interest rate, an additional 1.97% and 0.99% of interest on the carrying amount of the secured bonds payable was being credited due to debt premiums and 1.63% of interest on the carrying amount of the subordinated debt discount was being incurred due to the debt discount recorded at the time of purchase. At December 31, 2004, there was $100 million of unamortized debt discount associated with Sithe long-term debt.

(c) Long-term debt maturities in the periods 2006 through 2010 and thereafter are as follows:

Year
2006	$	12
2007		12
2008		12
2009		11
2010		2
Thereafter		1,756
Total	$	1,805

Issuances of Long-Term Debt. Generation did not issue any long-term debt during 2005.

Debt Retirements and Redemptions.The following debt was retired, through tender, open market purchases, optional redemption or payment at maturity, during 2005:

Type	Interest Rate		Maturity	Amount
Note payable	6.33	%	August 8, 2009	$	10
Other					4
Total retirements				$	14

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Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Debt totaling approximately $820 million was eliminated from Generation’s Consolidated Balance Sheets as a result of the sale of Sithe on January 31, 2005. See Note 3—Acquisitions and Dispositions for further discussion regarding the sale of Sithe.

See Note 16—Fair Value of Financial Assets and Liabilities for additional information regarding interest-rate swaps of Generation.

12. Income Taxes

Generation’s income tax expense (benefit) from continuing operations is comprised of the following components:

	For the Year Ended December 31,
	2005			2004			2003
Included in operations:
Federal
Current	$	315		$	230		$	(227	)
Deferred		270			114			81
Investment tax credit amortization		(8	)		(8	)		(8	)
State
Current		69			19			(4	)
Deferred		63			46			(21	)
Total income tax expense (benefit)	$	709		$	401		$	(179	)
Included in cumulative effects of changes in accounting principles:
Deferred
Federal	$	(16	)	$	17		$	58
State		(3	)		5			12
Total income tax expense (benefit)	$	(19	)	$	22		$	70

Generation’s effective income tax rate from continuing operations differed from the U.S. Federal statutory rate principally due to the following:

	For the Year Ended December 31,
	2005		2004		2003
U.S. Federal statutory rate	35.0%		35.0%		35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	4.7		4.0		3.9
Qualified nuclear decommissioning trust fund income	0.9		(0.7	)	(2.1	)
Manufacturer’s deduction	(0.8	)	—		—
Tax exempt income	(0.6	)	(0.9	)	1.8
Amortization of investment tax credit	(0.2	)	(0.5	)	1.2
Nontaxable postretirement benefits	(0.3	)	(0.3	)	—
Deferred expense/revenue option adjustment	—		—		1.6
Other	0.3		1.5		1.6
Effective income tax rate	39.0%		38.1%		43.0%

392

Exelon Generation Company, LLC 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 Generation’s deferred tax assets and liabilities as of December 31, 2005 and 2004 are presented below:

	December 31,
	2005			2004
Deferred tax liabilities:
Deferred pension and postretirement obligations	$	(177	)	$	—
Plant basis difference		(861	)		(790	)
Emission allowances		(40	)		(39	)
Total deferred tax liabilities		(1,078	)		(829	)
Deferred tax assets:
Decommissioning and decontamination obligations		105			153
Deferred pension and postretirement obligations		—			69
Unrealized losses on derivative financial instruments		194			66
Other, net		151			83
Total deferred tax assets		450			371
Deferred income tax liabilities (net) on the Consolidated Balance Sheets	$	(628	)	$	(458	)

In 2005 and 2004, Generation received $16 million and $26 million, respectively, from Exelon related to its allocation of tax benefits under the Tax Sharing Agreement. Generation received no allocation of tax benefits under the Tax Sharing Agreement in 2003.

Generation had unamortized investment tax credits of $202 million and $210 million at December 31, 2005 and December 31, 2004, respectively.

As of December 31, 2005 and 2004, Generation (excluding Sithe) had capital loss carry forwards for income tax purposes of approximately $129 million and $163 million, respectively, which expire beginning in 2009. As of December 31, 2005, the Mexican net operating loss carry forwards of Generation’s subsidiaries are $77 million, which will expire beginning in 2011.

As of December 31, 2005 and 2004, Generation had recorded valuation allowances of approximately $3 million and $5 million, respectively, with respect to deferred taxes associated with separate company state taxes. As of December 31, 2004, Sithe had capital loss carry forwards for income tax purposes of approximately $21 million, which will expire beginning in 2007 and an Alternative Minimum Tax carry forward of approximately $26 million which can be carried forward indefinitely. In addition as of December 31, 2004, Sithe had domestic and Mexican net operating loss carry forwards of approximately $101 million and $57 million, respectively. As of January 31, 2005, these carry forwards are no longer included as deferred tax assets on Generation’s books, as Sithe was sold in the first quarter of 2005.

13. Nuclear Decommissioning and Spent Fuel Storage

Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. Generation will pay for this obligation using trust funds that have been established for this purpose. These trust funds have been funded through prior and current

393

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

collections from customers. The trust funds established for a particular plant may not be used to fund the decommissioning obligation of any other nuclear plant. Generation believes that these funds, along with future collections from customers for decommissioning, will ultimately be sufficient to satisfy all required decommissioning-related activities.

The following table summarizes the most significant assets and liabilities associated with nuclear decommissioning included in Generation’s Consolidated Balance Sheets as of December 31, 2005 and 2004:

December 31, 2005
Property, plant and equipment (asset retirement cost)	$	685
Nuclear decommissioning trust funds		5,585
Long-term payables to affiliates		(1,503	)
Asset retirement obligation		(3,921	)
Other comprehensive income, net		(76	)
December 31, 2004
Property, plant and equipment (asset retirement cost)	$	961
Nuclear decommissioning trust funds		5,262
Long-term payables to affiliates		(1,479	)
Asset retirement obligation		(3,980	)
Other comprehensive income, net		(62	)

Nuclear Decommissioning Obligations

Generation assumed the responsibility for decommissioning the former ComEd and former PECO nuclear units as a result of a corporate restructuring effective January 1, 2001 in which Exelon separated its generation and other competitive businesses from its regulated energy delivery business at ComEd and PECO.

AmerGen, which became a wholly owned subsidiary of Generation in December 2003, assumed responsibility for decommissioning the Three Mile Island, Clinton and Oyster Creek units upon the original purchase of each unit in 1999, 1999 and 2000, respectively.

Generation will begin decommissioning activities for each plant once that plant ceases operations. The majority of Generation’s decommissioning activity is anticipated to begin after 2029. Generation currently makes decommissioning payments for its retired units; however, those amounts are not considered significant when compared to the total obligation.

As of December 31, 2005 and 2004, Generation had recorded nuclear decommissioning obligations totaling $3,921 million and $3,980 million, respectively, which were determined in accordance with SFAS No. 143. See Note 1—Significant Accounting Policies for information regarding the adoption and application of SFAS No. 143.

Nuclear Decommissioning Trust Funds

The trust funds that have been established to satisfy Generation’s nuclear decommissioning obligations were originally funded with amounts collected by customers. In certain circumstances, these trust funds will continue to be funded by future collections from customers.

394

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

The trust funds associated with the former ComEd units and the former PECO units have been funded with amounts collected from the ComEd and PECO customers, respectively. Any funds remaining in these trusts after decommissioning has been completed are required to be refunded to ComEd or PECO’s customers as appropriate. Conversely, if there are insufficient funds in the trusts associated with the former ComEd units to pay for decommissioning costs, Generation is required to fund that shortfall. Any potential shortfall is determined on a plant-by-plant basis, since the trust funds established for any particular plant may not be used to fund the decommissioning obligations of any other plant.

If there are insufficient funds in the trusts associated with the former PECO units, PECO is allowed to collect additional amounts from the PECO customers, subject to certain limitations, as prescribed by an order from the Pennsylvania Public Utility Commission (PAPUC). Generally, PECO will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds compared to decommissioning obligations, as well as 5% of any additional shortfalls. This initial $50 million will be borne by Generation as required by the corporate restructuring in 2001. Accordingly, the order from the PAPUC currently allows PECO to seek additional collections to fund 95% of the shortfall, after the initial $50 million that is not eligible for reimbursement from customers.

AmerGen is financially responsible for the decommissioning of the AmerGen plants and retains any funds remaining in the trusts after decommissioning of those plants has been completed. Any shortfall of funds necessary for decommissioning is required to be funded by AmerGen.

As of December 31, 2005 and 2004, nuclear decommissioning trust funds totaled $5,585 million and $5,262 million, respectively. See Note 16—Fair Value of Financial Assets and Liabilities for more information regarding the nuclear decommissioning trust funds as of December 31, 2005 and 2004.

Current Collections from Customers

Through 2006, ComEd is permitted to collect up to $73 million annually from customers to pay for decommissioning costs. These amounts are collected by ComEd and remitted to Generation on a monthly basis. In 2005 and 2004, ComEd collected and remitted to Generation a total of $68 million and $73 million, respectively. ComEd is not permitted to collect any amounts after 2006 to pay for decommissioning costs; accordingly, any trust fund deficiencies, as determined on a plant-by-plant basis, for decommissioning obligations related to the former ComEd plants will be funded by Generation.

PECO is permitted to collect amounts to fund decommissioning costs through the retirement dates of each of the former PECO nuclear units. Currently, PECO collects $33 million annually from customers to pay for these decommissioning costs. These amounts are collected by PECO and remitted to Generation on a monthly basis. Every five years, the PAPUC reviews the annual amount that PECO is allowed to collect from customers. In both 2005 and 2004, PECO collected and remitted to Generation $33 million. In the event the PAPUC reduces or eliminates the amount PECO is permitted to collect from customers, Generation anticipates that any trust fund deficiencies for decommissioning obligations related to the former PECO plants would be funded by Generation.

AmerGen does not currently collect any amounts from customers, nor is there any mechanism by which Generation can seek to collect additional amounts from customers in order to pay the decommissioning costs of the AmerGen units.

395

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Accounting Implications of the Agreements with ComEd and PECO

Impact on the Statements of Income

As discussed above, the ComEd and PECO customers are entitled to a refund of any excess, as determined on a plant-by-plant basis, of trust funds that remain after the completion of decommissioning activities. Because the funds held in trust currently exceed the total estimated decommissioning obligation, Generation does not recognize in the statement of income the net impacts of decommissioning the former ComEd and former PECO units. However, should the decommissioning obligations associated with the former ComEd units exceed the related decommissioning assets, Generation will no longer offset the net impacts of decommissioning activities related to these plants in the statements of income.

Decommissioning impacts, including the accretion of the decommissioning obligation (which is included in operating and maintenance expense in the statements of income) and the income of the trust funds (net of applicable taxes) associated with the former ComEd and former PECO units, are offset within the statements of income with an equal adjustment to non-current affiliate payable. Likewise, ComEd and PECO have recorded equal non-current affiliate receivables from Generation and corresponding regulatory liabilities. The statements of income reflect the decommissioning impacts associated with the AmerGen units, as there are no regulatory agreements associated with these units.

Impact on the Statements of Other Comprehensive Income

Generation does not reflect any net activity within the statement of other comprehensive income related to the unrealized gains and losses for the trust funds established to fund the decommissioning liabilities of the former PECO units as these unrealized gains and losses are not anticipated to ultimately be included in the statement of income as a result of the current accounting, as discussed above. Unrealized gains and losses (after applicable taxes) related to the former ComEd units are also offset within the statement of other comprehensive income. The gross unrealized gains and losses in the trust funds of the former ComEd and PECO units are tax-effected at the applicable tax rates, so that the associated deferred tax assets and liabilities can be appropriately calculated and recorded.

The net unrealized gains and losses associated with AmerGen are included in the statement of other comprehensive income, since the accounting treatment described above does not apply to AmerGen.

Impact on the Balance Sheet

The decommissioning liabilities associated with the former ComEd, former PECO and AmerGen units are reflected as an asset retirement obligation (ARO) in the long-term liability section of the balance sheet. AROs represent legal obligations associated with the retirement of tangible long-lived assets. Changes in the ARO resulting from revisions to the timing or amount of future undiscounted cash flows are generally recognized through a corresponding increase or decrease to the carrying value of that plant. This adjustment is reflected in property, plant and equipment as an asset retirement cost (ARC), and is amortized on a straight-line basis over the life of that plant.

The non-current affiliate payables from Generation to ComEd and PECO represent the difference between the decommissioning-related assets and decommissioning-related liabilities, which are required to be refunded to ComEd or PECO’s customers as appropriate. ComEd and PECO have recorded corresponding non-current affiliate receivables from Generation and corresponding regulatory liabilities to the applicable customers.

396

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

The following table provides a roll forward of the decommissioning liability, which is reflected as an ARO on Generation’s Consolidated Balance Sheets, from January 1, 2004 to December 31, 2005:

Asset retirement obligation at January 1, 2004	$	2,996
Net increase resulting from updates to estimated future cash flows		780
Accretion expense		210
Additional liabilities incurred(a)		6
Payments to decommission retired plants		(12	)
Asset retirement obligation at December 31, 2004		3,980
Net decrease resulting from updates to estimated future cash flows		(281	)
Accretion expense		243
Liabilities reclassified and disposed(b)		(7	)
Payments to decommission retired plants		(14	)
Asset retirement obligation at December 31, 2005	$	3,921

(a) Additional liabilities incurred are primarily due to the consolidation of Sithe.

(b) Represents the reclassification of $(4) million related to fossil and hydroelectric generating facilities and $(3) million related to liabilities disposed as a result of the sale of Sithe on January 31, 2005.

2005 and 2004 ARO Updates

In 2005, Generation recorded a $281 million net decrease in the ARO resulting from revisions to estimated future nuclear decommissioning cash flows. This decrease resulted primarily from a year-over-year decline in the cost escalation factors used to estimate future undiscounted costs, partially offset by an increase resulting from updated decommissioning cost studies received for two nuclear stations. Both the updated cost escalation factors and the updated cost studies were provided by independent third-party appraisers.

In 2004, Generation recorded a $780 million net increase in the ARO resulting from revisions to estimated future nuclear decommissioning cash flows. This increase resulted primarily from updated decommissioning cost studies and changes in cost escalation factors used to estimate future undiscounted costs, both of which were provided by independent third-party appraisers.

Spent Nuclear Fuel

Under the Nuclear Waste Policy Act of 1982 (NWPA), the U.S. Department of Energy (DOE) is responsible for the development of a repository for the disposal of spent nuclear fuel (SNF) and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from its nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation pays the DOE one mill ($.001) per kilowatt-hour of net nuclear generation for the cost of nuclear fuel long-term disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts 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 2012. This extended delay in SNF acceptance by the DOE has led to Generation’s adoption of dry cask storage at its Dresden, Quad Cities, Oyster Creek and Peach Bottom stations and its consideration of dry cask storage at other stations.

397

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. PECO’s fee has been paid. Pursuant to the Standard Contracts, 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, 2005, the unfunded liability for the one-time fee with interest was $906 million. Interest accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect, for calculation of the interest accrual at December 31, 2005, was 3.983%. The liabilities for spent nuclear fuel disposal costs, including the one-time fee, were transferred to Generation as part of the 2001 corporate restructuring. The one-time fee obligation for the AmerGen units, except for Clinton, remains with the prior owner. Clinton has no outstanding obligation.

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 granted the Government’s motion to dismiss claims other than the breach of contract claims. Also on June 10, 2003, the Court denied the Government’s summary judgment motions and set the case for trial on damages for November 2004.

In July 2000, PECO entered into an agreement (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 Contracts. Under the Amendment, the DOE agreed to provide PECO with credits against PECO’s future contributions to the Nuclear Waste Fund 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 grounds 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 provided 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 Contracts would remain in effect and the parties would return to pre-Amendment status. 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 continued to record an interest

398

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

expense each subsequent month. Generation 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.

On July 21, 2004, Exelon and the U.S. Department of Justice, in close consultation with the DOE, reached a settlement under which the government will reimburse Generation for costs associated with storage of spent fuel at Generation’s nuclear stations pending DOE’s fulfillment of its obligations. Under the agreement, Generation immediately received $80 million in gross reimbursements for storage costs already incurred ($53 million net after considering amounts due from Generation to co-owners of certain nuclear stations), with additional amounts to be reimbursed annually for future costs. Also under the agreement, during the third quarter of 2004, Generation made full reimbursement of $41.9 million to the Nuclear Waste Fund for prior credits plus lost earnings as set forth in the DOE Contracting Officer’s letter dated August 14, 2003. In 2005, Generation received $58 million in gross reimbursements for storage costs incurred between October 1, 2003 and June 30, 2005, ($35 million net, after considering amounts due from Generation to co-owners and previous owners of certain nuclear stations). As of December 31, 2005, the amount of spent fuel storage costs for which reimbursement will be requested from the DOE under the settlement agreement is $14 million gross, which is recorded within accounts receivable, other. This amount is comprised of $6 million, which has been recorded as a reduction to operating and maintenance expense, and $5 million, which has been recorded as a reduction to capital expenditures. The remaining $3 million represents amounts owed to the co-owners of the Peach Bottom and Quad Cities generating facilities. In all cases, reimbursements will be made only after costs are incurred and only for costs resulting from DOE delays in accepting the fuel.

14. Conditional ARO

As of December 31, 2005, Generation adopted FIN 47, which clarified that a legal obligation associated with the retirement of a long-lived asset whose timing and/or method of settlement are conditional on a future event is within the scope of SFAS No. 143. Under FIN 47, Generation is required to record liabilities associated with its conditional AROs at their estimated fair values if those fair values can be reasonably estimated.

Determination of Conditional AROs

The adoption of FIN 47 required Generation to update an existing inventory, originally created for the adoption of SFAS No. 143, and to determine which, if any, of the conditional AROs could be reasonably estimated. The significant conditional AROs identified by Generation included plant closure costs associated with its fossil and hydroelectric generating stations, including asbestos abatement, removal of certain storage tanks and other decommissioning-related activities.

The ability to reasonably estimate a conditional ARO was a matter of management judgment, based upon management’s ability to estimate a settlement date or range of settlement dates, a method or potential method of settlement and probabilities associated with the potential dates and methods of settlement of its conditional AROs. In determining whether its conditional AROs could be reasonably estimated, management considered Generation’s past practices, industry practices, management’s intent and the estimated economic lives of the assets. The management of Generation concluded that all significant conditional AROs could be reasonably estimated.

399

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Generation was required to measure the conditional AROs at fair value using the methodology prescribed by FIN 47. The transition provisions of FIN 47 required Generation to apply this measurement back to the historical periods in which the conditional AROs were incurred, resulting in a remeasurement of these obligations at the latter of the date that the related assets were placed into service or acquired or the date that the applicable law or environmental regulation became effective. The fair values of the conditional AROs were then estimated using a probability-weighted, discounted cash flow model with multiple scenarios, if applicable. The present value of future estimated cash flows was calculated using credit-adjusted, risk-free rates applicable to Generation in order to determine the fair value of the conditional AROs at the time of adoption of FIN 47.

Conditional AROs of $61 million were recorded as of December 31, 2005 by Generation. Changes in management’s assumptions regarding settlement dates, settlement methods or assigned probabilities could have had a material effect on the liabilities recorded at December 31, 2005 as well as the associated cumulative effect of a change in accounting principle.

Effect of Adopting FIN 47

FIN 47 required that Generation recognize the following amounts within its financial statements upon the adoption of FIN 47: (i) a liability for any existing conditional AROs adjusted for cumulative accretion to December 31, 2005; (ii) an ARC capitalized as an increase to the carrying amount of the associated long-lived assets; and (iii) cumulative depreciation on the ARC. The transition guidance in FIN 47 required that its adoption be effected through a cumulative change in accounting principle measured as the difference between the amounts recognized in the financial statements prior to the adoption of FIN 47 for conditional AROs and the amounts recognized as of December 31, 2005 pursuant to FIN 47.

After considering the transitional guidance included in FIN 47, Generation recorded a charge of $30 million (net of income taxes of $19 million) as a cumulative effect of a change in accounting principle in connection with the adoption of FIN 47.

The following table presents the line items within Generation’s Consolidated Statements of Income for the year ended December 31, 2005 and the Consolidated Balance Sheets at December 31, 2005 that were affected by the adoption of FIN 47:

Consolidated statements of income line item:
Cumulative effect of a change in accounting principle (net of income taxes of $(19))(a)	$	(30	)
Consolidated balance sheets line items—increase (decrease):
Property, plant and equipment, net(b)		12
Deferred income taxes (noncurrent liability)		(19	)
Asset retirement obligations(c)		61

(a) Represents the difference between the conditional ARO and net ARC recorded upon adoption, net of income taxes.

(b) Represents capitalized ARC of $22 million as an increase to the carrying amount of the associated long-lived assets, net of accumulated depreciation of $10 million on the ARC.

(c) Represents a liability for existing conditional AROs adjusted for cumulative accretion to December 31, 2005.

400

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

See Note 1—Significant Accounting Policies for net income for 2005, 2004 and 2003, adjusted as if FIN 47 had been applied effective during the entirety of those years. The following table presents, on a pro forma basis, what the liability for conditional AROs would have been had FIN 47 been applied during the years 2004 and 2003. These pro forma amounts are estimated based upon the information, assumptions, and interest rates used to measure the liability for conditional AROs recognized upon adoption of FIN 47 as of December 31, 2005.

Pro forma liability for conditional AROs, January 1, 2003(a)	$	54
Pro forma liability for conditional AROs, December 31, 2003(a)		57
Pro forma liability for conditional AROs, December 31, 2004(a)		61

(a) Includes AROs related to fossil and hydroelectric generating stations previously recorded upon the adoption of SFAS No. 143.

Prospective Accounting Methodology Under FIN 47

The liabilities associated with conditional AROs will be adjusted on an ongoing basis due to the passage of time, new laws and regulations and revisions to either the timing or amount of the original estimates of undiscounted cash flows. These adjustments could have a significant impact on Generation’s Consolidated Statements of Income and Consolidated Balance Sheets.

The liabilities recorded as of December 31, 2005 related to the conditional AROs of Generation will be accreted to their full estimated settlement amounts through the estimated ultimate settlement dates. This accretion charge will be recorded as an operating and maintenance expense within Generation’s Consolidated Statements of Income.

The net ARC recorded as of December 31, 2005 by Generation will be depreciated over the remaining lives of the related long-lived assets. This charge will be recorded as a depreciation and amortization expense within Generation’s Consolidated Statements of Income.

15. Retirement Benefits

Generation participates in defined benefit pension plans and postretirement welfare benefit plans sponsored by Exelon. Substantially all eligible Generation employees participate in the Exelon sponsored 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, in addition to 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. Employees of AmerGen participate in separate defined benefit pension plans and postretirement welfare benefit plans sponsored by AmerGen. In 2005, AmerGen offered its employees a choice to remain in their traditional benefit formula or convert to a cash balance formula. In 2004, AmerGen offered its employees a choice to remain in their traditional benefit formula or convert to a cash balance formula. This choice period expired in early 2005.

The prepaid pension asset, pension obligation and non-pension postretirement benefits obligation on Generation’s Consolidated Balance Sheets reflect Generation’s obligations from and to the plan sponsors, Exelon and AmerGen. Employee-related assets and liabilities, including both pension and SFAS No. 106 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.

401

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Exelon allocates the components of pension expense to the participating employers based upon several factors, including the percentage of active employees in each participating unit.

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

Approximately $97 million, $126 million and $75 million were included in capital and operating and maintenance expense, excluding curtailment/settlement costs and special termination benefits costs during 2005, 2004 and 2003, respectively, for Generation’s allocated portion of Exelon’s pension and post-retirement benefit expense. The 2005 and 2004 amounts reflect an annualized reduction in net periodic postretirement benefit cost of $15 million and $12 million, respectively, related to a Federal subsidy provided under the Prescription Drug Act. This subsidy has been accounted for under FSP FAS 106-2, as described in Note 1—Significant Accounting Policies. Generation contributed $962 million, $180 million and $145 million to the Exelon-sponsored pension plans in 2005, 2004 and 2003, respectively. Of Generation’s total 2005 contributions, $844 million was made in the first quarter and was primarily funded by a capital contribution from Exelon. Generation does not expect to contribute to Exelon’s pension benefit plans in 2006.

During 2005, Generation recognized no curtailment charges or special termination benefit costs. During 2004 and 2003, Generation recognized curtailment charges of $3 million and $18 million (before income taxes), respectively, associated with an overall reduction in participants in Exelon’s pension and postretirement benefit plans due to employee reductions. During 2004 and 2003, Generation recognized special termination benefit costs of $4 million and $20 million, respectively, (before income taxes).

Included in Generation’s 2005 and 2004 results are costs associated with pension benefit and other postretirement benefit plans sponsored by AmerGen. Costs associated with the pension and postretirement benefits were $9 million and $10 million, respectively for 2005 and $11 million and $11 million, respectively for 2004. At December 31, 2005 and 2004, Generation’s balance sheet included a liability of $14 million and $21 million, respectively, related to the pension obligation and $99 million and $90 million, respectively, related to other postretirement benefit obligations.

The accumulated benefit obligation (ABO) for the AmerGen pension plan was $95 million and $77 million at December 31, 2005 and 2004, respectively. The projected benefit obligation (PBO) for the AmerGen pension plan was $107 million and $90 million at December 31, 2005 and 2004, respectively. The fair value of plan assets related to this obligation was $70 million and $53 million at December 31, 2005 and 2004, respectively. Generation expects to contribute $11 million to AmerGen’s pension benefit plan in 2006.

The postretirement benefit plan for AmerGen is unfunded. At December 31, 2005 and 2004, the accumulated postretirement benefit obligation (APBO) related to postretirement benefits was $82 million and $94 million, respectively. In 2005, AmerGen recognized savings related to the adoption of FSP FAS 106-2 for the postretirement welfare plan.

Generation participates in a 401(k) savings plan sponsored by Exelon. The plan allows employees to contribute a portion of their pre-tax income in accordance with specified guidelines. Generation matches a percentage of the employee contribution up to certain limits. The cost of Generation’s matching contributions to the savings plan totaled $28 million, $27 million and $24 million for 2005, 2004 and 2003, respectively.

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Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

16. Fair Value of Financial Assets and Liabilities

Non-Derivative Financial Assets and Liabilities

Fair Value.As of December 31, 2005 and 2004, Generation’s carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities are representative of fair value because of the short-term nature of these instruments. Fair values for long-term debt are determined by an external valuation model which is based on conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves.

The carrying amounts and fair values of Generation’s financial liabilities as of December 31, 2005 and 2004 were as follows:

	2005				2004
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year)	$	1,800	$	1,856	$	2,630	$	3,002

Credit Risk.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.

Generation would also be exposed to credit-related losses in the event of non-performance by counterparties that issue derivative instruments. The credit exposure of derivative contracts is represented by the fair value of contracts at the reporting date. The notional amount of derivatives does not represent amounts that are exchanged by the parties and, thus, are 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.

Energy-Related Derivatives

Generation utilizes derivatives to manage the utilization of its available generating capacity and the 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. Generation’s energy contracts are accounted for under SFAS No. 133. Non-trading contracts may qualify for the normal purchases and normal sales exemption to SFAS No. 133. Those that do not meet the normal purchase and normal sales exemption are recorded as assets or liabilities on the balance sheet at fair value. Changes in the derivatives recorded at fair value are recognized in earnings unless specific hedge accounting criteria are met and they are designated as cash-flow hedges, in which case those changes are recorded in OCI, and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet the hedge criteria under SFAS No. 133 (or are not designated as such) and proprietary trading contracts are recognized in current earnings. Generation also has contracted for access to additional generation and sales to load-serving entities that are accounted for under the accrual method of accounting discussed in Note 17—Commitments and Contingencies.

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Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

At December 31, 2005, there were net liabilities of $540 million on Generation’s Consolidated Balance Sheets for the fair value of energy derivatives, which included the energy derivatives at Generation discussed below. The following tables provide a summary of the fair value balances recorded by Generation as of December 31, 2005:

December 31, 2005
Derivatives	Cash-Flow Hedges			Other Derivatives			Proprietary Trading			Total
Current assets	$	563		$	327		$	26		$	916
Noncurrent assets		153			9			124			286
Total mark-to-market energy contract assets	$	716		$	336		$	150		$	1,202
Current liabilities	$	(948	)	$	(316	)	$	(18	)	$	(1,282	)
Noncurrent liabilities		(289	)		(48	)		(123	)		(460	)
Total mark-to-market energy contract liabilities	$	(1,237	)	$	(364	)	$	(141	)	$	(1,742	)
Total mark-to-market energy contract net assets (liabilities)	$	(521	)	$	(28	)	$	9		$	(540	)

At December 31, 2004, there were net liabilities of $145 million on Generation’s Consolidated Balance Sheets for the fair value of energy derivatives, which included the energy derivatives at Generation discussed below. The following table provides a summary of the fair value balances recorded by Generation as of December 31, 2004:

December 31, 2004
Derivatives	Cash-Flow Hedges			Other Derivatives			Proprietary Trading		Total
Current assets	$	295		$	106		$	2	$	403
Noncurrent assets		132			240			1		373
Total mark-to-market energy contract assets	$	427		$	346		$	3	$	776
Current liabilities	$	(489	)	$	(109	)	$	—	$	(598	)
Noncurrent liabilities		(162	)		(161	)		—		(323	)
Total mark-to-market energy contract liabilities	$	(651	)	$	(270	)	$	—	$	(921	)
Total mark-to-market energy contract net assets (liabilities)	$	(224	)	$	76		$	3	$	(145	)

Normal Operations and Hedging Activities.Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including ComEd’s and PECO’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 anticipated exposures.

Cash-Flow Hedges

The tables below provide details of effective cash-flow hedges under SFAS No. 133 included on Generation’s Consolidated Balance Sheets as of December 31, 2005. The data in the table is indicative of the magnitude of SFAS No. 133 hedges Generation has in place; however, since under

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Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

SFAS No. 133 not all derivatives are recorded in OCI, the table does not provide an all-encompassing picture of Generation’s derivatives. The tables also include a rollforward of accumulated OCI related to cash-flow hedges for the years ended December 31, 2005 and 2004, providing information about the changes in the fair value of hedges and the reclassification from OCI into earnings.

December 31, 2005	Total Cash-Flow Hedge OCI Activity, Net of Income Tax
Accumulated OCI derivative loss at January 1, 2005	$	(137	)
Changes in fair value		(533	)
Reclassifications from OCI to net income		356
Accumulated OCI derivative loss at December 31, 2005	$	(314	)
December 31, 2004	Total Cash-Flow Hedge OCI Activity, Net of Income Tax
Accumulated OCI derivative loss at January 1, 2004	$	(133	)
Changes in fair value		(312	)
Disposal of existing Boston Generating contracts		16
Reclassifications from OCI to net income		290
Exelon Energy opening balance		2
Accumulated OCI derivative loss at December 31, 2004	$	(137	)

At December 31, 2005, Generation had net unrealized pre-tax losses of $521 million of cash-flow hedges recorded in accumulated OCI. Based on market prices at December 31, 2005, approximately $386 million of these deferred net pre-tax unrealized losses on derivative instruments in accumulated OCI are expected to be reclassified to earnings during the next twelve months. However, the actual amount reclassified to earnings could vary due to future changes in market prices. Amounts recorded in accumulated OCI 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 three years.

Generation’s cash-flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $583 million pre-tax loss, a $475 million pre-tax loss and a $273 million pre-tax loss for the years ended December 31, 2005, 2004 and 2003 respectively.

Other Derivatives

Generation enters into certain contracts that are derivatives, but do not qualify for hedge accounting under SFAS No. 133 or are not designated as cash-flow hedges. These contracts are also entered into to economically hedge and limit the market price risk associated with energy commodity prices. Changes in the fair value of these derivative contracts are recognized in current earnings. For 2005, 2004, and 2003, Generation recognized the following net unrealized mark-to-market gains, realized mark-to-market losses and total mark-to-market gains (losses) (before income taxes) relating

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Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

to mark-to-market activity of certain non-trading purchase power and sale contracts pursuant to SFAS No. 133. Mark-to-market activity on non-trading purchase power and sale contracts are reported in fuel and purchased power.

	For the Year Ended December 31,
	2005			2004			2003
Unrealized mark-to-market gains	$	86		$	181		$	207
Realized mark-to-market losses		(98	)		(183	)		(223	)
Total net mark-to-market gains (losses)	$	(12	)	$	(2	)	$	(16	)

Proprietary Trading Activities. Proprietary trading includes all contracts entered into purely to profit from market price changes as opposed to hedging an exposure and is subject to limits established by the Risk Management Committee. 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. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a very small portion of Generation’s overall energy marketing activities. For 2005, 2004 and 2003, Generation recognized the following net unrealized mark-to-market gains, realized mark-to-market gains (losses) and total mark-to-market gains (before income taxes) 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 Generation’s Consolidated Statements of Income.

	For the Year Ended December 31,
	2005			2004			2003
Unrealized mark-to-market gains (losses)	$	18		$	3		$	(3	)
Realized mark-to-market gains (losses)		(3	)		(3	)		4
Total net mark-to-market gains	$	15		$	—		$	1

Credit Risk Associated with Derivative Instruments.Generation would be exposed to credit-related losses in the event of non-performance by counterparties that issue derivative instruments. The credit exposure of derivatives contracts is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, 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 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.

Nuclear Decommissioning Trust Fund Investments

Investments as of December 31, 2005 and 2004.Generation classifies investments in trust accounts for decommissioning nuclear plants as available-for-sale and estimates their fair value based on quoted market prices for the securities held in trust funds. These investments are held to fund Generation’s decommissioning obligation for its nuclear plants. Decommissioning expenditures are expected to occur primarily after the plants are retired. Based on current licenses and anticipated renewals, decommissioning expenditures for plants in operation are currently estimated to begin after 2029. See Note 13—Nuclear Decommissioning and Spent Fuel Storage for further information regarding the decommissioning of Generation’s nuclear plants.

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Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

The following tables show the fair values, gross unrealized gains and losses and amortized cost bases of the securities held in these trust accounts as of December 31, 2005 and 2004.

	December 31, 2005
	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
Cash and cash equivalents	$	80	$	—	$	—		$	80
Marketable equity securities		2,762		683		(32	)		3,413
U.S. Treasury obligations and direct obligations of U.S. government agencies		361		32		(6	)		387
Other debt securities		1,695		19		(9	)		1,705
Total available-for-sale securities	$	4,898	$	734	$	(47	)	$	5,585
	December 31, 2004
	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Estimated Fair Value
Cash and cash equivalents	$	184	$	—	$	—		$	184
Equity securities		2,194		538		(37	)		2,695
U.S. Treasury obligations and direct obligations of U.S. government agencies		1,447		51		(4	)		1,494
Other debt securities		855		37		(3	)		889
Total available-for-sale securities	$	4,680	$	626	$	(44	)	$	5,262

The fixed-income available-for-sale securities held at December 31, 2005 have an average maturity range of seven to ten years. The cost of these securities was determined on the basis of specific identification.

Impairment Evaluation in 2005.At December 31, 2005, Generation had gross unrealized gains of $734 million and gross unrealized losses of $47 million related to the nuclear decommissioning trust fund investments. At December 31, 2004, Generation had gross unrealized gains of $626 million and gross unrealized losses of $44 million related to the nuclear decommissioning trust fund investments. With the exception of the portion of these amounts primarily related to AmerGen and as a result of ComEd’s and PECO’s regulatory arrangements for decommissioning costs, approximately $556 million and $469 million of these net unrealized gains were recorded as an increase in Generation’s noncurrent affiliate payables as of December 31, 2005 and 2004, respectively.

Generation evaluates decommissioning trust fund investments for other-than-temporary impairments by analyzing the historical performance, cost basis and market value of securities in unrealized loss positions in comparison to related market indices. Generation evaluates whether certain trust fund investments are other-than-temporarily impaired based on various factors assessed in the aggregate, including the duration and severity of the impairment, the anticipated recovery of the securities and considerations of Generation’s ability and intent to hold the investments until the recovery of their cost basis. This evaluation resulted in a $2 million and $8 million impairment charge recorded in other income and deductions associated with the decommissioning trust funds of the AmerGen plants during the years ended December 31, 2005 and 2004, respectively. Also, Generation

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Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

realized $20 million and $260 million of impairment charges associated with the trust funds for the decommissioning of the former ComEd and former PECO plants during the years ended December 31, 2005 and 2004, respectively. Recognition of these impairment charges associated with the former ComEd and former PECO plants had no net income impact on Generation’s results of operations or financial position.

Unrealized Gains and Losses.Net unrealized gains of $687 million and $582 million were included in noncurrent affiliate payables or accumulated other comprehensive income in Generation’s Consolidated Balance Sheets at December 31, 2005 and 2004, respectively.

The following table provides information regarding available-for-sale securities held in nuclear decommissioning trust funds in an unrealized loss position that were not considered other-than-temporarily impaired. The following tables show 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, 2005 and 2004.

	December 31, 2005
	Less than 12 months					12 months or more					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
Marketable equity securities	$	345	$	(23	)	$	69	$	(9	)	$	414	$	(32	)
U.S. Treasury obligations and direct obligations of U.S. government agencies		433		(5	)		28		(1	)		461		(6	)
Other debt securities		275		(5	)		73		(4	)		348		(9	)
Total	$	1,053	$	(33	)	$	170	$	(14	)	$	1,223	$	(47	)
	December 31, 2004
	Less than 12 months					12 months or more					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
Marketable equity securities	$	197	$	(16	)	$	278	$	(21	)	$	475	$	(37	)
U.S. Treasury obligations and direct obligations of U.S. government agencies		207		(2	)		68		(2	)		275		(4	)
Other debt securities		182		(2	)		22		(1	)		204		(3	)
Total	$	586	$	(20	)	$	368	$	(24	)	$	954	$	(44	)

Generation evaluates the historical performance, cost basis and market value of securities in unrealized loss positions in comparison to related market indices to assess whether or not the securities are other-than-temporarily impaired. Generation concluded that the trending of the related market indices, the historical performance of these securities over a long-term time horizon and the level of insignificance of the unrealized loss as a percentage of the cost of the individual securities indicates that the securities are not other-than-temporarily impaired.

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Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Sale of Nuclear Decommissioning Trust Fund Investments.Proceeds from the sale of decommissioning trust fund investments and gross realized gains and losses on those sales for the years ended December 31, 2005, 2004 and 2003 were as follows:

	For the Years Ended December 31,
	2005			2004			2003
Proceeds from sales	$	5,274		$	2,320		$	2,341
Gross realized gains		130			115			219
Gross realized losses		(81	)		(43	)		(235	)

17. Commitments and Contingencies

Nuclear Insurance

The Price-Anderson Act limits the liability of nuclear reactor owners for claims that could arise from a single incident. As of December 31, 2005, the limit is $10.76 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. Through its subsidiaries, Generation carries the maximum available commercial insurance of $300 million for each operating site and the remaining $10.46 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. The maximum assessment for all nuclear operators per reactor per incident (including a 5% surcharge) is $100.6 million, payable at no more than $15 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 was extended to December 31, 2025 under the Energy Act Policy.

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 $176 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 insured plants, 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 extended, 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

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Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

experience. Generation’s maximum share of any assessment is $47 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 extended, 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 its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Generation’s financial condition, results of operations and liquidity.

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 purchase 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 purchase power agreements (PPAs). These agreements are firm commitments related to power generation of specific generation plants and/or are dispatchable in nature. Generation enters into purchase power agreements 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.

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Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

At December 31, 2005, Generation had long-term commitments, relating to the purchase from and sale to unaffiliated utilities and others of energy, capacity and transmission rights as indicated in the following tables:

	Net Capacity Purchases (a)		Power Only Sales		Power Only Purchases		Transmission Rights Purchases
2006	$	616	$	2,783	$	1,508	$	7
2007		527		947		491		3
2008		460		80		194		—
2009		434		18		194		—
2010		436		19		194		—
Thereafter		3,391		—		355		—
Total	$	5,864	$	3,847	$	2,936	$	10

(a) Net capacity purchases include tolling agreements that are accounted for as operating leases. Amounts presented in the commitments represent Generation’s expected payments under these arrangements at December 31, 2005. Expected payments include certain capacity charges which are contingent on plant availability.

Generation has a PPA with ComEd under which Generation has agreed to supply substantially all of ComEd’s energy and capacity through 2006. Prices for this energy vary depending upon the time of day and month of delivery. Subsequent to 2006, ComEd expects to procure all of its supply from market sources, which could include Generation. Additionally, Generation has entered into a PPA with PECO under which PECO obtains substantially all of its electric supply from Generation through 2010. Prices for this energy vary depending upon month of delivery. Subsequent to 2010, PECO expects to procure all of its supply from market sources, which could include Generation.

Fuel Purchase Obligations

Generation has commitments to purchase fuel supplies for nuclear and fossil generation. As of December 31, 2005, these commitments were as follows:

			Expiration within
	Total		2006		2007-2008		2009-2010		2011 and beyond
Fuel purchase agreements	$	4,299	$	754	$	1,235	$	933	$	1,377

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Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Commercial Commitments

Generation’s commercial commitments as of December 31, 2005, representing commitments potentially triggered by future events, were as follows:

			Expiration within
	Total		2006		2007-2008		2009-2010		2011 and beyond
Letters of credit (non-debt)(a)	$	47	$	47	$	—	$	—	$	—
Letters of credit (long-term debt)—interest coverage(b)		15		15		—		—		—
Performance guarantees(c)		201		—		—		—		201
Energy marketing contract guarantees(d)		208		131		—		—		77
Nuclear insurance premiums(e)		1,710		—		—		—		1,710
Exelon New England guarantees(f)		14		—		—		—		14
Other		7		7		—		—		—
Total commercial commitments	$	2,202	$	200	$	—	$	—	$	2,002

(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 $14 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 $520 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.

(f) Exelon New England guarantees—Mystic Development LLC (Mystic), a former affiliate of Exelon New England, has a long-term agreement through January 2020 with Distrigas of Massachusetts Corporation (Distrigas) for gas supply, primarily for the Boston Generating units. Under the agreement, gas purchase prices from Distrigas are indexed to the New England gas markets. Exelon New England has guaranteed Mystic’s financial obligations to Distrigas under the long-term supply agreement. Exelon New England’s guarantee to Distrigas remained in effect following the transfer of ownership interest in Boston Generating in May 2004. Under FIN 45, approximately $14 million is included as a noncurrent liability within the Consolidated Balance Sheets of Generation as of December 31, 2005 related to this guarantee. The terms of the guarantee do not limit the potential future payments that Exelon New England could be required to make under the guarantee. Other guarantees associated with Exelon New England total less than $1 million.

Environmental Issues

General.Generation’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, Generation is generally liable for the costs of remediating environmental contamination of property now or formerly owned by Generation and of property contaminated by hazardous substances generated by Generation. Generation 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. In addition, 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, 2005 and December 31, 2004, Generation had accrued $27 million and $16 million, respectively, for environmental liabilities.

412

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Generation cannot reasonably estimate whether they 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, including customers.

Section 316(b) of the Clean Water Act.In July 2004, the EPA issued the final Phase II rule implementing Section 316(b) of the Clean Water Act. This rule establishes national requirements for reducing the adverse environmental impacts from the entrainment and impingement of aquatic organisms at existing power plants. The rule identifies particular standards of performance with respect to entrainment and impingement and requires each facility to monitor and validate this performance in future years. The requirements will be implemented through state-level National Pollutant Discharge Elimination System (NPDES) permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g. cooling towers) are potentially most affected. Those facilities are Clinton, Cromby, Dresden, Eddystone, Fairless Hills, Handley, Mountain Creek, New Boston, Oyster Creek, Peach Bottom, Quad Cities and Salem. Generation is currently evaluating compliance options at its affected plants. At this time, Generation cannot estimate the effect that compliance with the Phase II rule requirements will have on the operation of its generating facilities and its future results of operations, financial condition and cash flows. There are many factors to be considered and evaluated to determine how Generation will comply with the Phase II rule requirements and the extent to which such compliance may result in financial and operational impacts. The considerations and evaluations include, but are not limited to obtaining clarifying interpretations of the requirements from state regulators, resolving outstanding litigation proceedings concerning the requirements, completing studies to establish biological baselines for each facility and performing environmental and economic cost benefit evaluations of the potential compliance alternatives in accordance with the requirements.

In a pre-draft permit dated May 13, 2005 and a draft permit issued on July 19, 2005, as part of the pending National Pollution Discharge Elimination System permit renewal process for Oyster Creek, the New Jersey Department of Environmental Protection (NJDEP) preliminarily determined that closed-cycle cooling and environmental restoration are the only viable compliance options for Section 316(b) compliance at Oyster Creek. AmerGen has not made a determination regarding how it will demonstrate compliance with the Section 316(b) regulations, but believes that other compliance options under the final Phase II rule are viable and will be analyzed as part of the plant’s comprehensive demonstration study.

In June 2001, the NJDEP issued a renewed NDPES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised PSEG in a letter dated July 12, 2004 that it strongly recommended reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG submitted an application for a renewal of the permit on February 1, 2006. In the permit renewal application, PSEG analyzed closed-cycle cooling and other options and demonstrated that the continuation of the Estuary Enhancement Program, an extensive environmental restoration program at Salem, is the best technology to meet the Section 316(b) requirements. If application of the Section 316(b) regulations ultimately requires the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, Generation’s share of the total cost of the retrofit and any resulting interim replacement power would likely be in excess of $500 million and could result in increased depreciation expense related to the retrofit investment.

413

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions, except per share data unless otherwise noted)

Nuclear Generating Station Groundwater.On December 16, 2005, the Illinois Environmental Protection Agency issued a Violation Notice to Generation alleging that the company had violated state groundwater standards due to a discharge of liquid tritium from a line at the Braidwood Nuclear Generating Station. As of December 31, 2005, Generation recorded a reserve of $7 million (pre-tax) for this matter, which Generation deems adequate to cover the costs of remediation and potential related corrective measures. See Note 21—Subsequent Events for further details of this and similar matters.

Cotter Corporation.The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. 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 any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. 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 the anticipated remediation strategy for the site range up to $22 million. Once a remedy is selected, it is expected that the PRPs will agree on an allocation of responsibility for the costs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of the liability.

Leases

Minimum future operating lease payments, including lease payments for vehicles, real estate, computers, rail cars and office equipment, as of December 31, 2005 were:

2006	$	31
2007		30
2008		29
2009		27
2010		26
Remaining years		391
Total minimum future lease payments (a)	$	534

(a) Excludes Generation’s tolling agreements that are accounted for as operating leases and are reflected as net capacity purchases in the energy commitments table above.

Generation’s rental expense under operating leases totaled $30 million, $33 million and $24 million in 2005, 2004, and 2003, respectively. For information regarding Generation’s capital lease obligations, see Note 11– Long Term Debt.

Litigation

PJM Billing Dispute.In December 2004, Exelon filed a complaint against PJM and PPL Electric with the FERC alleging that PJM had overcharged Exelon from April 1998 through May 2003 as a result of a billing error. Specifically, the complaint alleges that PJM mistakenly identified PPL Electric’s

414

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Elroy substation transformer as belonging to Exelon and that, as a consequence, during times of congestion, Exelon’s bills for transmission congestion from PJM erroneously reflected energy that PPL Electric took from the Elroy substation and used to serve PPL Electric’s load. The complaint requested the FERC, among other things, to direct PPL Electric to refund to PJM $39.1 million, plus interest of approximately $8 million, and for PJM to refund these same amounts to Exelon.

On September 14, 2005, Exelon and PPL filed a proposed settlement of this matter with the FERC. If the settlement is approved by the FERC, Exelon will receive a total of $40.5 million, plus interest, over the next four years from two funding sources: (a) $33 million from PPL Electric; and (b) $7.5 million from PJM market participants. It is anticipated that approximately 75% of the proposed settlement will be received by Generation. Both charges will be collected and paid by PJM over a four-year period following FERC approval of the settlement with interest on the unpaid principal accruing over the collection and payment period. As Exelon is a market participant in PJM, if this settlement is approved by the FERC, the net amount of the settlement to be received by Exelon will be reduced by Exelon’s portion of the $7.5 million described above.

Pending FERC approval of the settlement, Generation has not recorded any receivables associated with this matter.

Asbestos Personal Injury Claims.Like many other industrial companies, Generation is a defendant in personal injury actions related to asbestos exposure in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The vast majority of these asbestos-related bodily injury claims allege a variety of lung-related diseases based on alleged exposure to asbestos by former third-party contractors involved in the original construction or maintenance of the facilities. The construction of these facilities primarily occurred between 1950 and 1975. Generation does not have significant asbestos-related bodily injury claims occurring after 1980.

As part of the 2001 restructuring in which Generation purchased ComEd’s and PECO’s energy-producing facilities, Generation assumed all of ComEd’s and PECO’s current and future benefits and liabilities associated with these facilities. Based on the receipt of asbestos-related bodily injury claims during 2002, 2003 and 2004, where previously an insignificant number of claims were received and corresponding expenses were recorded, Generation engaged independent actuaries to determine if a reasonable estimate of future losses could be made based on historical claims data and other available information. Based on the currently available volume and diversity of historical claim and payment data, the actuaries determined that a reasonable estimate could be prepared and, accordingly, Generation engaged the actuaries to calculate an estimate of future losses. In the second quarter of 2005, based on the actuaries’ analyses, management’s review of current and expected losses and the view of counsel regarding the assumptions used in estimating the future losses, Generation recorded an undiscounted $43 million pre-tax charge for its estimated portion of all estimated future asbestos-related personal injury claims estimated to be presented through 2030. This amount does not include estimated legal costs associated with handling these matters, which could be material. Generation management determined that it was not reasonable to estimate future asbestos-related personal injury claims past 2030 based on only three years of historical claims data and the significant amount of judgment required to estimate this liability. In calculating future losses, management and the actuaries made various assumptions, including, but not limited to, the overall number of future claims estimated through the use of actuarial models, Generation’s estimated portion of future settlements and obligations, the distribution of exposure sites, the anticipated future mix of diseases that relate to asbestos exposure and the anticipated levels of awards made to plaintiffs. Generation’s recent history

415

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

of successfully defending itself in court cases for asbestos-related bodily injury claims was qualitatively considered in determining this estimate.

The amounts recorded by Generation for estimated future asbestos-related bodily injury claims are based upon known facts at the time the report was prepared. Projecting future events, such as the number of new claims to be filed each year and the average cost of disposing of claims, as well as the numerous uncertainties surrounding asbestos-related litigation in the United States, could cause the actual costs to be higher or lower than projected. While it is not possible to predict the ultimate outcome of the asbestos-related claims and settlements, management believes, after consultation with counsel, that resolution of these matters is not expected to have a material adverse effect on Generation’s results of operations and financial position. Management cautions, however, that these estimates for asbestos-related bodily injury cases and settlements are difficult to predict and may be influenced by many factors. Accordingly, these matters, if resolved in a manner different from the estimate, could have a material effect on or Generation’s results of operations, financial position and cash flow.

The $43 million pre-tax charge was recorded as part of operating and maintenance expense on Generation’s Consolidated Statements of Income in 2005 and reduced net income by $27 million. At December 31, 2005 and 2004, Generation had approximately $50 million and $10 million, respectively, reserved in total for asbestos-related bodily injury claims. As of December 31, 2005, approximately $9 million of this amount relates to 120 open claims presented to Generation, while the remaining $41 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2030 based on actuarial assumptions and analysis. Generation plans to obtain annual updates of the estimate of future losses. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments.

Oil Spill Liability Trust Fund Claim. In December 2004, the two Salem nuclear generation units were taken offline due to an oil spill from a tanker in the Delaware River near the facilities. The units, which draw water from the river for cooling purposes, were taken offline for approximately two weeks to avoid intake of the spilled oil, resulting in lost sales from the plant. Generation and PSEG have filed a joint claim for losses and damages with the Oil Spill Liability Trust Fund. As this matter represents a contingent gain, Generation has recorded no income resulting from this claim. However, Generation’s management believes it is reasonably possible that damages and losses will be recovered and that Generation’s portion of the estimated proceeds arising from the claim will be approximately $25 million. Generation expects this matter to be resolved in 2006.

Real Estate Tax Appeals. Generation has been challenging real estate taxes assessed on nuclear plants. Generation is involved in real estate tax appeals for 2000 through 2004 regarding the valuation of its Limerick and Peach Bottom plants, Quad Cities Station (Rock Island County, IL), Three Mile Island Nuclear Station (Dauphin County, PA) (TMI), Oyster Creek Station (Forked River, NJ) and LaSalle County Station (Seneca, IL). Generation has reached settlements with the taxing authorities over the Limerick real estate assessments for 1998 and 1999. Pursuant to the settlement agreement, all Limerick tax appeals were dismissed by the state court, and Generation has agreed to make additional payments in lieu of taxes for years 2005 through 2008. In addition, Generation reached a settlement with the taxing authorities over the TMI real estate assessment, which has been approved by the state court. As a result of the TMI settlement, Generation reduced its real estate tax reserve balance by $6 million in the first quarter of 2005. Generation reached an agreement with the taxing authorities for all years under appeal for the Quad Cities station and the court approved the agreement on December 9, 2005. Generation also recently reached an agreement with the taxing authorities for all years under appeal for the Oyster Creek

416

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

station and an order implementing Oyster Creek’s property tax settlement was entered on December 16, 2005. In addition, on December 22, 2005, Generation reached an agreement for the 2005 tax year with the taxing authorities for LaSalle County Station, and is working towards court approval by the end of the first quarter of 2006.

Generation believes its reserve balances for other exposures associated with real estate taxes as of December 31, 2005 and 2004 reflect the probable expected outcome of the litigation and appeals proceedings in accordance with SFAS No. 5. The ultimate outcome of such matters, however, could result in unfavorable or favorable adjustments to the consolidated financial statements of Generation and such adjustments could be material.

Reverse-Employment Discrimination Claim. On April 4, 2005, one employee of PECO and four employees of Generation commenced suit in the United States District Court for the Eastern District of Pennsylvania, alleging that they were subjected to a practice of reverse-employment discrimination which denied promotional opportunities to older white male employees, purportedly in violation of various Federal antidiscrimination statutes and the Pennsylvania Human Relations Act. The plaintiffs filed the action individually and on behalf of a putative class that includes all white males currently or previously employed with any Exelon companies in the United States who were at least 40 years old on April 4, 2003 and who either applied for or were eligible to apply for supervisory positions in March 2003 and thereafter, continuing to the present day, and were not selected for these positions. The defendants have filed an answer denying all liability and are proceeding with discovery pertaining to the class allegations and the named plaintiffs’ individual claims. In December 2005, the Court ordered the case to be suspended until April 3, 2006 while the parties attempt to resolve this matter through non-binding mediation. As this case is in the early stages, Exelon cannot predict the outcome; however, Exelon does not expect this claim to have a material adverse effect on Exelon’s financial condition, results of operations or cash flows.

General. Generation is involved in various other litigation matters that are being defended and handled in the ordinary course of business. Generation maintains accruals for such costs that are probable of being incurred and subject to reasonable estimation. The ultimate outcomes of such matters, as well as the matters discussed above, are uncertain and may have a material adverse effect on Generation’s financial condition, results of operations or cash flows.

Capital Commitments

Generation has a 72% interest in SCEP, which owns a peaking facility in Chicago. SCEP is obligated to make total equity distributions of $46 million through 2022 to the party, which is not affiliated with Exelon, that owns the remaining 28% interest. This amount reflects a return of that party’s investment in SCEP. 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 28% interest in SCEP. Additionally, Generation may be required to purchase the remaining 28% interest upon the occurrence of certain events, including Generation’s failure to maintain an investment grade rating. The total long-term liability related to SCEP was $46 million and $49 million as of December 31, 2005 and 2004, respectively.

Fund Transfer Restrictions

Under applicable law, Generation can pay dividends only from undistributed or current earnings. At December 31, 2005 and 2004, Generation had undistributed earnings of $1,002 million and $761 million, respectively.

417

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Jointly Owned Electric Utility Plant

On January 28, 2004, the NRC issued a letter requesting PSEG to conduct a review of its Salem facility, of which Generation owns 42.59%, to assess the workplace environment for raising and addressing safety issues. PSEG responded to the letter on February 28, 2004 and had independent assessments of the work environment at both facilities performed. Assessment results were provided to the NRC in May 2004. The assessments concluded that Salem was safe for continued operation, but also identified issues that need to be addressed. At an NRC public meeting on June 16, 2004, PSEG outlined its action plans to address these issues, which focus on safety conscious work environment, the corrective action program and work management. A letter documenting these plans and commitments was sent to the NRC on June 25, 2004. PSEG provided the NRC a report of its progress and the progress of its actions to resolve identified issues at public meetings in 2004 and 2005. PSEG continues to publish the metrics that demonstrate performance that commenced in the fourth quarter of 2004.

18. Supplemental Financial Information

Supplemental Income Statement Information

The following tables provide additional information about Generation’s Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003.

	For the Years Ended December 31,
	2005		2004		2003
Depreciation, amortization and accretion
Property, plant and equipment(a)	$	254	$	294	$	199
Nuclear fuel(b)		385		381		395
Asset retirement obligation accretion		243		210		160
Amortization of intangibles		4		38		—
Total depreciation, amortization and accretion	$	886	$	923	$	754

(a) Includes amortization of capitalized software costs.

(b) Included in fuel expense in Generation’s Consolidated Statements of Income.

	For the Years Ended December 31,
	2005		2004		2003
Taxes other than income
Real estate	$	88	$	107	$	83
Payroll		54		48		39
Other		28		11		(2	)
Total taxes other than income	$	170	$	166	$	120

418

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

	For the Years Ended December 31,
	2005			2004			2003
Income (loss) in equity method investments
AmerGen(a)	$	—		$	—		$	47
Sithe(b)		—			(2	)		2
Sithe(c)		—			(9	)		—
TEG and TEP(d)		(1	)		(3	)		—
Total income (loss) in equity method investments	$	(1	)	$	(14	)	$	49

(a) Prior to the acquisition of British Energy’s 50% interest in December 2003.

(b) Prior to consolidation of EXRES SHC, Inc. in March 2004.

(c) Prior to acquisition of EXRES SHC, Inc. 49.5% interests in TEG and TEP in October 2004.

(d) After acquisition of EXRES SHC, Inc. 49.5% interests in TEG and TEP in October 2004.

	For the Years Ended December 31,
	2005			2004			2003
Other, net
Gain on sale of Boston Generating(a)	$	—		$	85		$	—
Decommissioning-related activities:
Decommissioning trust fund income(b)		135			194			79
Decommissioning trust fund income—AmerGen(b)		77			43			—
Other-than-temporary impairment of decommissioning trust funds		(22	)(d)		(268	)(e)		—
Contractual offset to non-operating decommissioning-related activities(c)		(115	)		66			(79	)
Impairment of investment in Sithe					—			(255	)
Other		20			10			(8	)
Total other, net	$	95		$	130		$	(263	)

(a) See Note 3—Acquisitions and Dispositions for further discussion of Generation’s sale of Boston Generating.

(b) Includes investment income and net realized gains.

(c) Includes the elimination of non-operating decommissioning-related activity for those units that are subject to contractual accounting, including the elimination of decommissioning trust fund income and other-than-temporary impairments for certain nuclear units. See Note 13—Nuclear Decommissioning and Spent Fuel Storage and Note 16—Fair Value of Financial Assets and Liabilities for more information regarding the contractual accounting applied for certain nuclear units.

(d) Includes other-than-temporary impairments for 2005 totaling $20 million, $0 on and $2 million on nuclear decommissioning trust funds for the former ComEd units, the former PECO units and AmerGen units, respectively.

(e) Includes other-than-temporary impairments for 2004 totaling $255 million, $5 million and $8 million on nuclear decommissioning trust funds for the former ComEd units, the former PECO units and AmerGen units, respectively.

419

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

Supplemental Cash Flow Information

As a result of adopting FIN 47 as of December 31, 2005, Generation recorded an ARC of $22 million, which was capitalized as an increase to the carrying amount of long-lived assets associated with liabilities recorded for conditional AROs. This amount resulted in a non-cash investing activity. See Note 14—Conditional ARO for additional information on the adoption of FIN 47. In addition to this non-cash activity, the following table provides additional information about Generation’s Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003.

	For the Years Ended December 31,
	2005			2004			2003
Cash paid (received) during the year
Interest (net of amount capitalized)	$	121		$	163		$	57
Income taxes (net of refunds)		242			20			(14	)
Non-cash investing and financing activities
Purchase accounting estimate adjustment	$	(11	)	$	22		$	59
Consolidation of Sithe pursuant to FIN 46-R		—			85			—
Disposal of Boston Generating(a)		—			102			—
Increase (decrease) in asset retirement cost asset		(251	)		829			—
Sale of asset		4			—			—
Note received in conjunction with the sale of Sithe to Reservoir		—			—			92
Note cancelled in connection with the acquisition of Sithe International from Sithe		—			92			—
Capital lease obligations		—			1			—
Non-cash (distribution) contribution (to) from member		16			(4	)		(17	)
Note issued to Sithe in the Exelon New England acquisition		—			—			2

(a) See Note 3—Acquisitions and Dispositions for additional information regarding the disposition of Boston Generating.

Supplemental Balance Sheet Information

The following tables provide additional information about assets recorded within Generation’s Consolidated Balance Sheets as of December 31, 2005 and 2004.

	December 31,
	2005		2004
Investments
Investment in TEG and TEP(a)	$	90	$	79
Investment in Keystone Fuels, LLC and Conemaugh Fuels, LLC		13		9
Other		17		15
Total investments	$	120	$	103

(a) Generation acquired a 49.5% interest in two facilities in Mexico on October 13, 2004. See Note 3—Acquisitions and Dispositions for further information on this transaction.

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Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

The following table provides additional information about liabilities recorded within Generation’s Consolidated Balance Sheets as of December 31, 2005 and 2004.

	December 31,
	2005		2004
Accrued expenses
Compensation-related accruals(a)	$	195	$	185
Taxes accrued		147		98
Interest accrued		15		36
Other		58		48
Total accrued expenses	$	415	$	367

(a) Primarily included accrued payroll, bonuses and other incentives, vacation and benefits.

The following table provides information regarding counterparty margin deposit accounts as of December 31, 2005 and 2004.

	December 31,
	2005		2004
Other current assets
Counterparty collateral deposits paid	$	285	$	41
Other current liabilities
Counterparty collateral deposits received		101		44

The following table provides additional information about accumulated other comprehensive income recorded within Generation’s Consolidated Balance Sheets as of December 31, 2005 and 2004.

	December 31,
	2005			2004
Accumulated other comprehensive loss
Net unrealized loss on cash-flow hedges	$	(318	)	$	(146	)
Foreign currency translation adjustment		—			1
Net unrealized gain on marketable securities		76			62
Total accumulated other comprehensive loss	$	(242	)	$	(83	)

421

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

19. Related Party Transactions

Generation’s financial statements reflect related-party transactions as presented in the tables below:

	For the Years Ended December 31,
	2005		2004		2003
Operating revenues from affiliates
ComEd(a)	$	3,174	$	2,374	$	2,479
PECO(a)		1,672		1,465		1,433
Exelon Energy(b)		—		—		213
BSC(c)		2		2		—
Purchased power from affiliates
AmerGen(d)		—		—		382
ComEd(e)		—		9		38
Exelon Energy(b)		—		—		9
Fuel from affiliates
PECO(e)		1		1		—
Operating and Maintenance from affiliates
ComEd(e)		8		8		12
PECO(e)		7		8		10
BSC(c)		222		223		127
Interest expense to affiliates
Sithe(f)		—		—		9
Exelon intercompany money pool(g)		3		3		4
Interest income from affiliates
AmerGen(d)		—		—		1
Services provided to affiliates
AmerGen(d)		—		—		111
Cash distribution paid to member		857		662		189
Cash contribution received from member		843		17		—

	December 31,
	2005		2004
Receivables from affiliates (current)
ComEd(a)	$	242	$	189
ComEd decommissioning(i)		11		11
PECO(a)		151		125
BSC(c)		7		7
Note receivable from affiliate (noncurrent)
ComEd decommissioning(i)		—		11
Payable to affiliate (current)
Exelon(g)		4		42
Borrowings from Exelon intercompany money pool(g)		92		283
Payables to affiliates (noncurrent)
ComEd decommissioning(h)		1,435		1,433
PECO decommissioning(h)		68		46

422

Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

(a) Generation has entered into PPAs with ComEd and PECO, as amended, to provide the full energy requirements of ComEd and PECO. Effective April 1, 2004, Generation entered into a one-year gas supply agreement with PECO. See Note 17—Commitments and Contingencies for additional information regarding the PPAs.

(b) Prior to May 1, 2004, Generation sold power to Exelon Energy and purchased excess power from Exelon Energy. Prior to the transfer of Exelon Energy’s assets to Generation from Enterprises effective January 1, 2004, Exelon Energy was an intercompany affiliate of Generation.

(c) Generation receives a variety of corporate support services from Exelon Business Services Company (BSC), including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. Some third-party reimbursements due to Generation are recovered through BSC.

(d) Prior to Generation’s purchase of British Energy’s 50% interest in AmerGen in December 2003, AmerGen was an unconsolidated affiliate of Generation and was considered to be a related party of Generation. Generation entered into PPAs dated June 26, 2003, December 18, 2001 and November 22, 1999 with AmerGen. Under the 2003 PPA, Generation agreed to purchase from AmerGen all the energy from Oyster Creek through April 9, 2009. 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. The residual output was approximately 31% of the total output of Clinton. 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. 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.

(e) Generation purchases retail electric and ancillary services from ComEd and buys power from PECO for Generation’s own use. In order to facilitate payment processing, ComEd processes certain invoice payments on behalf of Generation. Prior to joining PJM on May 1, 2004, ComEd also provided transmission services to Generation. Amounts charged by ComEd to Generation for transmission have been recorded as intercompany purchased power by Generation. See Note 17—Commitments and Contingencies for additional information regarding the PPAs.

(f) Under a service agreement dated December 18, 2000, Sithe provided Generation certain fuel and project development services. Sithe was compensated for these services at cost. In December 2003, Sithe received letter of credit proceeds of $3 million, which Generation was billed on behalf of Sithe. Under the terms of the agreement to acquire Exelon New England dated November 1, 2002, Generation issued a note to Sithe that was subsequently modified and increased to $536 million. During 2003, Generation repaid $446 million of this note. In the first quarter of 2004, Generation repaid $27 million prior to consolidation of Sithe in accordance with the provisions of FIN 46-R. The balance of the note, which bore interest at the rate of LIBOR plus 0.875%, was paid upon the completion of a series of transactions that resulted in Generation’s sale of Sithe on January 31, 2005. See Note 3—Acquisitions and Dispositions for further information regarding the sale of Generation’s investment in Sithe.

(g) Generation participates in Exelon’s intercompany money pool. Generation earns interest on its contributions to the money pool, and pays interest on its borrowings from the money pool at a market rate of interest.

(h) Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO, such amounts are due back to ComEd and PECO, as applicable, for payment to the customers. See Note 13—Nuclear Decommissioning and Spent Fuel Storage for additional information.

(i) Generation has short-term and had a long-term receivable from ComEd, primarily representing ComEd’s legal requirements to remit collections of nuclear decommissioning costs from its customers to Generation.

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Exelon Generation Company, LLC and Subsidiary Companies

Notes to Consolidated Financial Statements—(Continued)

(Dollars in millions unless otherwise noted)

20. Quarterly Data (Unaudited)

The data shown below includes all adjustments that Generation 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
	2005		2004		2005		2004		2005		2004		2005		2004
Quarter ended:
March 31	$	2,020	$	1,946	$	506	$	128	$	320	$	70	$	320	$	102
June 30		2,105		1,881		456		231		296		178		296		178
September 30		2,711		2,151		575		528		335		319		335		319
December 31		2,210		1,726		316		151		177		74		147		74

21. Subsequent Events

Nuclear Generating Station Groundwater.On December 16, 2005, the Illinois Environmental Protection Agency (Illinois EPA) issued a Violation Notice to Generation alleging that the company had violated state groundwater standards as a result of historical discharges of liquid tritium from a line at the Braidwood Nuclear Generating Station. In November 2005, Generation discovered that spills from the line in 1998 and 2000 have resulted in a tritium plume in groundwater that is both on and off the plant site. Levels of tritium in portions of the plume are in excess of the Illinois EPA groundwater standard. Levels in portions of the plume also exceed the Illinois EPA and Federal limits for drinking water. However, samples from drinking water wells on property adjacent to the plant have shown that, with one exception, tritium levels in these wells are below levels that naturally occur. The tritium levels in one drinking water well is elevated above levels that naturally occur, but is significantly below the state and federal drinking water standards, and Generation believes that this level poses no threat to human health. Generation has suspended liquid tritium discharges into the affected pipeline, and is investigating the causes of the releases to ensure that necessary corrective actions are taken to prevent another occurrence. Generation has analyzed the various remediation options for the groundwater, and submitted an initial report to the Illinois EPA on February 2, 2006. The Illinois EPA will determine the required remediation and whether a civil penalty will be assessed against Generation. Generation has notified 14 potentially affected adjacent property owners that, upon sale of their property, it will reimburse them for any diminution in property value caused by the release, and has purchased the property of one adjacent owner. As of December 31, 2005, Generation recorded a reserve of $7 million (pre-tax) for this matter, which Generation deems adequate to cover the costs of remediation and potential related corrective measures.

Also, as a result of intensified monitoring and inspection efforts in 2006, Exelon detected a small underground tritium leak at the Dresden Generating Station and tritium concentrations in standing water within concrete vaults at the Byron Generating Station. Neither of these discharges occurred outside the property lines of the plant, nor does Exelon believe either of these matters poses health or safety threats to employees or to the public. In response to the detection of tritium in water samples taken at the aforementioned nuclear generating stations, Exelon has launched an initiative across its ten-station nuclear fleet to systematically assess systems that handle tritium and take the necessary actions to minimize the risk of inadvertent discharge of tritium to the environment. The assessments will take place in 2006 and will cover pipes, pumps, valves, tanks and other pieces of equipment that carry tritiated water in and around the plants. At this time, Exelon cannot estimate the costs that may be incurred connection with tritium assessment initiatives or in possible remediation efforts of the Dresden and Byron matters.

Credit Facilities Agreement. On February 10 through 13, 2006, Generation entered into separate additional credit facilities with aggregate bank commitments of $875 million, which may be drawn down in the form of loans and/or letters of credit. The additional credit facilities are each for a term of 364 days and contain the same terms as the revolving credit facilities described in Note 10—Short-Term Debt. The credit facilities will be used primarily to meet short-term funding requirements and to issue letters of credit.

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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, ComEd, PECO and Generation

During the fourth quarter of 2005, each registrant’s management, including its principal executive officer and principal financial officer, evaluated that registrant’s disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in that registrant’s periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by each registrant to ensure that (a) material information relating to that registrant, including its consolidated subsidiaries, is accumulated and made known to that registrant’s management, including its principal executive officer and principal financial officer, by other employees of that registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, 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.

Accordingly, as of December 31, 2005, the principal executive officer and principal financial officer of each registrant concluded that such registrant’s disclosure controls and procedures were effective to accomplish their objectives. Each registrant 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.

Exelon

Since Exelon is an accelerated filer, its management is required to assess and report on the effectiveness of its internal control over financial reporting as of December 31, 2005. As a result of that assessment, management determined that there were no material weaknesses as of December 31, 2005 and, therefore, concluded that Exelon’s internal control over financial reporting was effective. Management’s Report on Internal Control Over Financial Reporting is included in ITEM 8.—Financial Statements and Supplementary Data.

ITEM 9B. OTHER INFORMATION

Exelon

On February 13, 2006, Exelon amended the Senior Management Severance Plan with respect to certain terminations in connection with the Merger. The terms of the amendment are described under ITEM 11. Executive Compensation—“Change in Certain Employment Agreements and Severance Plans Covering Other Named Executives.”

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Exelon

Executive Officers

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, 2005.

Directors

Edward A. Brennan. Age 72. Director of Exelon Corporation since October 20, 2000. Class II director. Retired Chairman and CEO of Sears, Roebuck and Co. (retail merchandiser). Executive Chairman of AMR Corporation and American Airlines from April 2003 through May 2004. Other directorships: Allstate Corporation (NYSE: ALL); AMR Corporation (NYSE: AMR); 3M Company (NYSE: MMM); McDonald’s Corporation (NYSE: MCD); Morgan Stanley (NYSE: MWD).

M. Walter D’Alessio. Age 72. Director Of Exelon Corporation Since October 20, 2000. Class III Director. Director and Vice Chairman of NorthMarq Capital (real estate investment banking firm) and President and CEO of NorthMarq Advisors, LLC (real estate consulting group) since July 2003. Chairman and CEO, Legg Mason Real Estate Services, Inc. from 1982 through July 2003, non-executive chairman and director from July 2003 through present. Other directorships: Independence Blue Cross; Chairman, Brandywine Real Estate Investment Trust (NYSE: BDN); Pennsylvania Real Estate Investment Trust (NYSE: PEI); and Point Five Technologies.

Nicholas. DeBenedictis. Age 60. Director of Exelon Corporation since April 23, 2002. Class I director. Chairman and Chief Executive Officer of Aqua America Inc., (NYSE: WTR; water utility with operations in 12 states). Other Directorships: Met-Pro Corporation (NYSE: MPR); P.H. Glatfelter, Inc. (NYSE: GLT); Independence Blue Cross; Harleysville Mutual Insurance Company.

Bruce DeMars. Age 70. Director of Exelon Corporation since October 20, 2000. Class II director. Partner, RSD LLC (consulting firm which introduces new products to government and industry) since January 2001. Partner, Trident Merchant Group, May 1998 through December 2000. Retired Admiral, United States Navy and former Director of the Naval Nuclear Propulsion Program. Other Directorships: McDermott International Inc (NYSE: MDR); Chairman, Duratek Inc. (Provides low-level nuclear waste disposal services to Exelon. NASDAQ: DRTK); Oceanworks International, Inc.

Nelson A. Diaz. Age 58. Director of Exelon Corporation since January 27, 2004. Class II director. Partner, Blank Rome LLP (legal services) since March 2004. City Solicitor, City of Philadelphia, December 2001 through January 2004. Judge, Court of Common Pleas, First Judicial District of Pennsylvania, 1981 to 1993. Partner, Blank Rome Comisky & McCauley LLP (law firm), February 1997 through December 2001. General Counsel, United States Department of Housing and Urban Affairs, 1993 to 1997.

Sue L. Gin. Age 64. Director of Exelon Corporation since October 20, 2000. Class I director. Founder, Owner, Chairman and CEO of Flying Food Group, LLC (in-flight catering company). Other directorships: Centerplate, Inc. (AMEX: CVP).

Rosemarie B. Greco. Age 60. Director of Exelon Corporation since October 20, 2000. Class III director. Director of the Office of Health Care Reform, Commonwealth of Pennsylvania since January 2003. Founding Principal of GRECOventures Ltd. (management consulting firm). Former President of CoreStates Financial Corporation and former Director, President and CEO of CoreStates Bank, N.A.

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Other Directorships: Sunoco, Inc. (NYSE: SUN); Pennsylvania Real Estate Investment Trust. (NYSE: PEI); Trustee of SEI I Mutual Funds, a subsidiary of SEI Investments, Co. (NASDAQ: SEIC).

Edgar D. Jannotta. Age 74. Director of Exelon Corporation since October 20, 2000. Class I director. Chairman of William Blair & Company, L.L.C. (investment banking and brokerage company) since March 2001. Senior Director from 1996 through February 2001. Other Directorships: Aon Corporation (NYSE: AOC); Bandag, Incorporated (NYSE: BDG); Molex, Inc. (NASDAQ: MOLX).

John M. Palms, Ph.D. Age 70. Director of Exelon Corporation since October 20, 2000. Class III director. Distinguished President Emeritus of the University of South Carolina and Distinguished University Professor since July 2002. President from 1991 through June 2002. Former President of Georgia State University; Former Vice-President for Academic Affairs and the Charles Howard Chandler Professor of Physics at Emory University. Other Directorships: Chairman of Assurant Inc. (NYSE: AIZ); SIMCOM International Holdings, Inc.; Computer Task Group, Inc. (NYSE: CTG). Also Chairman of the Board of Trustees of the Institute for Defense Analyses, and formerly a member of the National Nuclear Accreditation Board and the Advisory Council for the Institute of Nuclear Power Operations.

William C. Richardson, Ph.D.Age 65. Director of Exelon Corporation since March 1, 2005. Class I director. President and CEO Emeritus effective January 1, 2006 of the W. K. Kellogg Foundation. President and CEO 1995 through 2005. Co-Trustee and Chair, W. K. Kellogg Foundation Trust. President Emeritus of Johns Hopkins University, 1990 through 1995. Other Directorships: Kellogg Company (NYSE: K); The Bank of New York Company, Inc. (NYSE: BK); CSX Corporation (NYSE: CSX).

Thomas J. Ridge. Age 60. Director of Exelon Corporation since May 2, 2005. Principal, Thomas Ridge, LLC. Secretary of the United States Department of Homeland Security from January 2003 through January 2005. Special Assistant to the President for Homeland Security, an Executive Office created by President Bush in October 2001, from October 2001 through December 2002. Governor of the Commonwealth of Pennsylvania from 1994 through October 2001. Other directorships: Home Depot Corporation (NYSE: HD); Savi Technology.

John W. Rogers, Jr. Age 48. Director of Exelon Corporation since October 20, 2000. Class III director. Founder, Chairman and CEO of Ariel Capital Management, Inc., LLC (an institutional money management firm). Other Directorships: Aon Corporation (NYSE: ACO); McDonalds Corporation (NYSE: MCD); Bally’s Total Fitness Holding Corporation (NYSE: BFT).

Ronald Rubin. Age 74. Director of Exelon Corporation since October 20, 2000. Class II director. Chairman and CEO of the Pennsylvania Real Estate Investment Trust (a real estate management and development company, NYSE: PEI).

John W. Rowe.Age 60. Director of Exelon Corporation since October 20, 2000. Class II director. Chairman, Chief Executive Officer and President of Exelon Corporation since November 2004; Chairman and Chief Executive Officer since April 2002, serving as President through May 2003; President and co-Chief Executive Officer from October 20, 2000 through April 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: The Northern Trust Company and Sunoco, Inc.

Richard L. Thomas. Age 75. Director of Exelon Corporation since October 20, 2000. Class III director. Retired Chairman of First Chicago NBD Corporation (banking and financial services) and the First National Bank of Chicago. Other Directorships: The PMI Group, Inc. (NYSE: PMI); SABRE Holdings Corporation (NYSE: TSG); Sara Lee Corporation (NYSE: SLE).

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Audit Committee

The Exelon audit committee consists of John M. Palms, Ph.D., its Chair, M. Walter D’Alessio, Sue L. Gin, William C. Richardson and Richard L. Thomas. The Exelon board of directors has determined that all members of the Exelon audit committee are independent directors, are financially literate, have accounting or related financial management expertise, and are “audit committee financial experts” under applicable SEC rules. Each member of the audit committee obtained these attributes through the business experience and directorships described above and through service on audit committees of various public companies, including the audit committees of Exelon’s predecessor companies, PECO and Unicom Corporation.

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 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, 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.

Section 16(a) Beneficial Ownership Reporting Compliance

Based upon signed affirmations received from directors and officers, as well as administrative review of company plans and accounts administered by private brokers on behalf of directors and officers which have been disclosed to Exelon by the individual directors and officers, Exelon believes that its directors and officers made all required filings on a timely basis during 2005.

ComEd

Executive Officers

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, 2005.

Directors

Frank M. Clark. Age 60. Chairman and Chief Executive Officer since November 28, 2005. Previously Vice President and Chief of Staff of Exelon and President of ComEd; Senior Vice President, distribution, customer and market 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. Other directorship: Waste Management, Inc. and Shorebank Corporation.

Sue L. Gin. Age 64. Director of Commonwealth Edison Company since November 28, 2005. Founder, Owner, Chairman and Chief Executive Officer of Flying Food Group, LLC. (in-flight catering company). Other directorships: Exelon Corporation; Centerplate, Inc.

Edgar D. Jannotta.Age 74. Director of Commonwealth Edison Company since November 28, 2005. Chairman of William Blair & Company, L.L.C. (investment banking and brokerage company). Other directorships: Exelon Corporation, Aon Corporation, Bandag, Incorporated and Molex Incorporated.

John W. Rogers, Jr. Age 48. Director of Commonwealth Edison Company since November 28, 2005. Founder, Chairman and CEO of Ariel Capital Management, LLC (an institutional money management firm). Trustee of Ariel Investment Trust. Other directorships: Exelon Corporation, Aon Corporation, McDonald’s Corporation and Bally Total Fitness Holding Corporation.

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Richard L. Thomas. Age 75. Director of Commonwealth Edison Company since November 28, 2005. Retired Chairman of First Chicago NBD Corporation (banking and financial services) and the First National Bank of Chicago. Other directorships: Exelon Corporation, The PMI Group, Inc., Sabre Holdings Corporation, and Sara Lee Corporation.

Audit Committee

The ComEd audit committee consists of John W. Rogers, Jr., its Chair, Sue L. Gin, Edgar D. Jannotta and Richard L. Thomas. The ComEd board of directors has determined that all members of the ComEd audit committee are independent directors.

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

Executive Officers

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, 2005.

Directors

Since the Merger date, the board of directors of PECO has been comprised solely of employees of Exelon, ComEd, PECO, or their subsidiaries. These individuals receive no additional compensation for serving as directors of PECO.

John W. Rowe.Age 60. Class I director since October 20, 2000. Chairman, Chief Executive Officer and President of Exelon Corporation since November 2004; Chairman and Chief Executive Officer since April 2002, serving as President through May 2003; President and co-Chief Executive Officer from October 20, 2000 through April 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: Exelon Corporation, The Northern Trust Company and Sunoco, Inc.

Denis P. O’Brien. Age 45. Class III director since June 30, 2003. President of PECO since April 2003. Previously Executive Vice President, Vice President of Operations, Director of Operations for the BucksMont Region and Director of Transmission and Substations.

John L. Skolds.Age 55. Class II director. Director since March 15, 2004. Executive Vice President of Exelon Corporation since February 1, 2004. Senior Vice President of Exelon and Exelon Generation Company, LLC and Chief Nuclear Officer from October 2000 through February 2004. Vice President of Unicom Corporation and ComEd, Chief Operating Officer, Nuclear Generation Group of ComEd from August 2000 through October 2000. President and Chief Operating Officer of South Carolina Electric and Gas from 1995 through August 2000.

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Audit Committee

PECO is a controlled subsidiary of Exelon and does not have a separate audit committee. Instead, that function is fulfilled by the audit committee of the Exelon board of directors. See discussion of Exelon’s audit committee above.

Code of Ethics

Exelon’s Code of Business Conduct is the code of ethics that applies to PECO’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, PECO will disclose the nature of such amendment or waiver on Exelon’s website,www.exeloncorp.com, or in a report on Form 8-K.

Generation

Executive Officers

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, 2005.

Directors

Generation operates as a limited liability company and has no board of directors.

Audit Committee

Generation is a controlled subsidiary of Exelon and does not have a separate audit committee. Instead, that function is fulfilled by the audit committee of the Exelon board of directors. See discussion of Exelon’s audit committee above.

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.

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.

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ITEM 11. EXECUTIVE COMPENSATION

Exelon

Non-Employee Directors Compensation

For their service as directors of the corporation, Exelon’s non-employee directors receive the compensation shown in the following table and explained in the accompanying notes. Employee directors receive no additional compensation for service as a director.

		Annual Board & Committee Retainers See Note (2)		Board Meeting Fees See Note (3)		Committee Meeting Fees See Note (3)		Deferred Stock Units See Note (4)		Total Compensation See Note (5)
Edward A. Brennan	2 (Ch), 3	$	40,000	$	18,000	$	10,500	$	60,000	$	128,500
M. Walter D’Alessio	1, 2, 3 (Ch),		45,000		19,500		27,000		60,000		151,500
Nicholas DeBenedictis	4, 5		40,000		19,500		13,500		60,000		133,000
Bruce DeMars	4, 5 (Ch)		45,000		18,000		13,500		60,000		136,500
Nelson A. Diaz	5, 6		40,000		19,500		13,500		60,000		133,000
Sue L. Gin	1, 6 (Ch)		45,000		19,500		24,000		60,000		148,500
Rosemarie B. Greco	2, 4 (Ch)		40,000		19,500		13,500		60,000		133,000
Edgar D. Jannotta	3, 6		35,000		16,500		9,000		60,000		120,500
John M. Palms	1 (Ch), 5		50,000		19,500		22,500		60,000		152,000
William C. Richardson	1, 4		33,444		12,000		13,500		50,167		109,111
Thomas J. Ridge	4, 5		25,769		13,500		6,000		39,890		85,159
John W. Rogers, Jr.	3, 4		35,000		19,500		10,500		60,000		125,000
Ronald Rubin	2, 6		35,000		19,500		12,000		60,000		126,500
Richard L. Thomas	1, 2, 3		40,000		19,500		27,000		60,000		146,500
Total All Directors		$	549,213	$	253,500	$	216,000	$	810,057	$	1,828,770

Notes to Non-Employee Directors Compensation

1. Key to committee membership: Audit = 1, Compensation = 2, Corporate Governance = 3, Energy Delivery Oversight = 4, Generation Oversight = 5, Risk Oversight = 6, committee chair = (ch).

2. All directors receive an annual retainer of $35,000. Committee chairs receive an additional $5,000 per year. Members of the Audit Committee and Generation Oversight Committee, including the committee chairs, receive an additional $5,000 per year membership retainer.

3. Directors receive a $1,500 meeting fee for each board and committee meeting attended, whether in person or by means of teleconferencing or video conferencing equipment. Directors also receive a $1,500 per diem for attending the annual shareholders meeting and for other occasional meetings with Exelon’s senior management.

4. All directors receive $60,000 worth of deferred stock units, which are distributed quarterly based upon the closing price of Exelon common stock on the day the quarterly dividend is paid. Deferred stock units are accrued in an unfunded notational account maintained by the company and earn the same dividends available to holders of Exelon common stock, which are reinvested in the account as additional units. Deferred stock units are settled as shares of Exelon common stock upon the director’s retirement from the board.

5. Directors may elect to defer any portion of their cash compensation into a non-qualified multi-fund deferred compensation plan. Each director has a notational account where the dollar balance can be invested in a basket of mutual funds including one fund composed entirely of Exelon common stock. These funds are identical to those available to company employees

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who participate in the Exelon Employee Savings Plan. Fund balances including those amounts invested in the Exelon common stock fund are settled in cash and may be distributed upon reaching age 65 or upon retirement from the board.

Other Compensation: For directors, Exelon pays the cost of their spouse’s travel, meals, and other related amenities when they are invited to attend company or industry related events where it is customary and expected that directors and officers attend with their spouses. The cost of such travel, meals and other amenities is imputed to the director as additional taxable income. However, in most cases the cost to Exelon of providing incremental transportation or other amenities for a director’s spouse is zero, and the only additional cost to Exelon is to reimburse directors for the taxes on the imputed income. In 2005, the aggregate amount paid to all directors as a group for reimbursement of taxes on imputed income was $7,074.

Directors are reimbursed for reasonable travel and lodging expenses incurred in attending board and committee meetings and when attending other matters on behalf of Exelon. Directors may also utilize Exelon’s corporate aircraft to travel to and from board and committee meetings. Directors may also request to receive cellular telephones or other personal electronic devices to be used primarily for Exelon business.

Exelon

Executive Compensation

The compensation shown for some executives in the following Summary Compensation table is also included in the Summary Compensation tables for other Registrants.

Summary Compensation Table

		Annual Compensation						Long Term Compensation
Name and Principal Position	Year	Salary		Bonus		Other Annual Compensation (See Note 1)		Restricted Stock Award (See Notes 2 and 3)		Number of Options (See Note 4) #	Payouts (See Notes 2 and 5)		All Other Compensation (See Notes 2 and 6)
John W. Rowe     Chairman, President & Chief Executive Officer, Exelon Corp.	2005 2004 2003	$	1,250,000 1,241,346 1,185,289	$	1,642,266 1,675,000 1,400,000	$	181,134 185,541 176,402	$	—   1,480,279 2,733,360	229,000 400,000 350,000	$	1,649,646 1,666,322 —	$	3,662,143 2,153,432 191,851
John L. Skolds Executive Vice President, Exelon Corp.	2005 2004 2003		603,808 571,154 530,673		509,998 462,239 393,837		34,126 3,472 2,762		—   739,118 634,530	56,000 80,000 80,000		406,454 426,400 —		899,437 514,883 64,276
Randall E. Mehrberg     Executive Vice President & General Counsel, Exelon Corp.	2005 2004 2003		532,923 494,807 466,538		451,474 469,000 375,418		63,793 6,159 6,248		406,454 404,218 634,530	56,000 80,000 72,000		406,454 426,400 —		470,905 499,737 49,741
John F. Young. Executive Vice President & Chief Financial Officer, Exelon Corp.	2005 2004 2003		539,615 435,807 311,923		443,113 505,680 214,159		238,872 5,066 144,943		812,850 330,695 494,236	56,000 54,000 30,000		406,454 348,842 —		62,006 415,106 185,973
Frank M. Clark Chairman and CEO, ComEd	2005 2004 2003		416,923 402,596 377,404		341,591 275,367 227,880		48,409 8,355 9,427		—   626,927 444,171	36,000 54,000 54,000		286,895 293,151 —		666,163 377,067 67,432

432

Notes to Summary Compensation Table

1. The amounts shown under the column labeled “Other Annual Compensation” include perquisites and amounts reimbursed for the payment of income taxes. Executive officers receive certain perquisites commensurate with their position. The amounts for such perquisites and their description are as follows:

	Personal and Spouse Travel		Automobile Lease and Parking		Financial, Estate and Tax Planning Services		Dining, Health and Airline Club Member- ships		Other Items		Reimburse- ment for Payment of Taxes		Total
John W. Rowe	$	102,617	$	19,116	$	15,591	$	10,114	$	14,400	$	19,296	$	181,134
John L. Skolds		2,060		15,517		10,240		2,370		439		3,500		34,126
Randall E. Mehrberg		1,444		21,355		30,600		4,940		411		5,043		63,793
John F. Young		3,855		17,955		22,306		1,395		156,696		36,665		238,872
Frank M. Clark		962		33,339		—		6,740		1,386		5,982		48,409

Personal and Spouse Travel:Mr. Rowe is entitled to 50 hours of personal use of corporate aircraft. The figure shown in the table above includes $100,481 representing the aggregate incremental cost to Exelon for Mr. Rowe’s personal use of company aircraft. For 2005 this cost was calculated using the hourly cost for flight services paid to the aircraft vendor, Federal excise tax, fuel charges, and domestic segment fees. In previous reports the cost of personal use of corporate aircraft for 2004 and 2003 included an allocation of fixed costs and allocated overhead that would have been incurred regardless of personal use of the aircraft. For Mr. Rowe, the amounts shown in this column in the Summary Compensation Table for 2004 and 2003 have been restated for comparability with the aggregate incremental cost approach used for 2005. From time to time, Mr. Rowe’s spouse accompanies Mr. Rowe in his travel on company aircraft. The aggregate incremental cost to the company, if any, for Mrs. Rowe’s personal use of company aircraft is included in the table. For all executive officers, including Mr. Rowe, Exelon pays the cost of their spouse’s travel, meals, and other related amenities when they attend company or industry related events where it is customary and expected that officers attend with their spouses. The aggregate incremental cost to Exelon for these expenses is included in the table. In most cases there is no incremental cost to Exelon of providing transportation or other amenities for a spouse, and the only additional cost to Exelon is to reimburse officers for the taxes on the imputed income attributable to their spouse’s travel, meals, and related amenities when attending company or industry related events. This cost is included in the column headed “Reimbursement for Payment of Taxes.”

Automobile Lease and Parking: Exelon provides officers with company vehicles, pays for insurance, maintenance, applicable taxes and provides a company paid credit card for fuel purchases. Where required, such as in downtown Chicago, officers also receive company paid parking. The figure shown in the table is the total cost for all automobile costs to the officer. For the named executive officers as a group a substantial majority of automobile use is for business purposes.

Financial, Estate, and Tax Planning Services: Officers may use any of these services through company-arranged vendors where the company pays for the service, or a vendor of their own choosing, for which the company will reimburse the officer for all reasonable expenses.

Dining, Health, and Airline Club Memberships:Officers are entitled to club memberships in each of the categories shown for the purpose of conducting business on behalf of the company. Membership in country clubs is not provided or reimbursed. The amounts shown represent only the payment of membership dues. Variable costs for meals and other amenities are the responsibility of each named officer. When any variable costs are business related, Exelon will reimburse the officer directly for such costs. A substantial majority of club use is for business purposes.

Other Items: Executive officers may use company provided vendors for comprehensive physical examinations and related follow-up testing. Exelon maintains several cars and company drivers to provide chauffeur services to executive officers for business purposes. Mr. Rowe is entitled to limited personal use of a company driver including for commuting purposes when in Chicago which enables him to perform work for the company while commuting. Mr. Clark is also entitled to limited personal use of company drivers. The aggregate incremental cost for Exelon to provide limited personal trips included in the table is estimated based on driver overtime, when applicable, and fuel cost. For Mr. Young, the value shown in the table includes a $100,000 relocation bonus and a moving allowance to relocate to the Chicago area.

Reimbursement forPayment of Taxes: Officers receive a reimbursement to cover applicable taxes on imputed amounts for business related spousal travel, certain club memberships and relocation expenses. For Mr. Young, the amount shown includes $32,624 for payment of taxes on his imputed relocation expense.

2. Exelon has a performance share award program under its Long Term Incentive Plan. Awards made prior to January 2005 were made in restricted stock that vested one-third upon the grant date and one-third upon each of the first and second anniversaries of the grant date. Beginning with awards made in January 2005 and for amounts vesting in 2005 and later, if the participant has achieved at least 125% of the participant’s stock ownership requirement, the performance shares are

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settled one-half in cash and one half in stock, with the same vesting schedule as before. Beginning with awards made in January 2006 and for amounts vesting in 2006, if the participant is an executive vice president or higher and has achieved more than 200% of the participant’s stock ownership requirement, the performance shares are settled entirely in cash.

For the 3 year performance period ended December 31, 2005, the named executive officers received performance share grants as shown in the following table; the shares were valued at $58.55, the NYSE closing price on January 23, 2006. The portion of the grants that will be settled in stock and will vest on the first and second anniversaries of the award is shown in column [C] below and in the column headed “Restricted Stock Awards” in the Summary Compensation Table above. The portion of the grants that vest immediately and is paid out in either cash or stock is shown in column [D] below and in the column headed “Long Term Compensation—Payouts” in the Table above. The remaining portion of the grants that may be settled in stock or cash (depending on the participant’s stock ownership on the relevant ownership measurement date is shown in column [E] below and in the column headed “All Other Compensation” in the Table above.

	[A] Number of Performance Shares #	[B] Total Value of Performance Share Award @ $58.55 / sh		[C] Value of Restricted Shares		[D] Value of Immediate Payout Settled in Cash or Shares		[E] Value of Future Payouts to be Settled in Cash or Shares
John W. Rowe	84,525	$	4,948,939	$	—	$	1,649,646	$	3,299,293
John L. Skolds	20,825		1,219,304		—		406,454		812,850
Randall E. Mehrberg	20,825		1,219,304		406,454		406,454		406,396
John F. Young	20,825		1,219,304		812,850		406,454		—
Frank M. Clark	14,700		860,685		—		286,895		573,790

3. This column reports the value of the restricted stock portion of performance share awards described above in Note 2 as well as other restricted awards granted to individuals during the preceding year by the Compensation Committee and the Board of Directors in recognition of specific accomplishments and/or significant increases in job responsibilities.

The named executive officers held the amounts of restricted shares, including unvested performance shares granted with respect to the three-year performance periods ending December 31, 2004 and December 31, 2003 as shown in column [A] below. Unvested restricted and performance shares continue to receive dividends.

Columns [C] and [D] in the following table include the amounts and value of restricted and unvested performance shares that were distributed and settled on January 23, 2006. This includes the first third of the current grant for the three-year period ending December 31, 2005, that is shown above in Note 2, as well as the second third of those shares granted with respect to the 3-year performance period ending December 31, 2004 and the last third of those shares granted with respect to the three-year performance period ended December 31, 2003. The shares are valued at the closing price of Exelon stock on January 23, 2006 which was $58.55. The value of this distribution and settlement is not included in the Summary Compensation Table.

Columns [E] and [F] show the amount and total value of the restricted shares and unvested performance shares remaining after the distribution and settlement as of January 23, 2006. The shares are valued at $58.55.

	[A] Number of Restricted Shares and Unvested Performance Shares as of 12/31/2005 #	[B] Number of Performance Shares Granted on 1/23/2006 #	[C] Number of Performance Shares That Were Vested and Settled on 1/23/2006 #	[D] Value of Performance Shares That Were Vested and Settled on 1/23/2006 $58.55 / sh		[E] Remaining Number of Restricted and Unvested Performance Shares [A] + [B] – [C] #	[F] Total Value of Remaining Shares Shown in Column [E] as of 1/23/2006 $58.55 / sh
John W. Rowe	110,123	84,525	98,178	$	5,748,343	96,470	$	5,648,319
John L. Skolds	46,725	20,825	24,145		1,413,707	43,405		2,541,363
Randall E. Mehrberg	27,470	20,825	24,145		1,413,707	24,150		1,413,983
John F. Young	25,855	20,825	19,398		1,135,737	27,282		1,597,361
Frank M. Clark	28,972	14,700	16,814		984,473	26,858		1,572,536

4. Options granted prior to May 5, 2004 reflect the effect of a 2 for 1 stock split as of that date.

5. The amounts shown under the column labeled “All Other Compensation” include company paid matching contributions to qualified and non-qualified savings plans along with the value of the unvested two-thirds of the performance share award granted with respect to the three-year performance period ending December 31, 2005 which will be paid out in cash or stock at the time of vesting in 2007 and 2008, depending upon the participants’ stock ownership at that time.

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	Value of Company Contributions to Savings Plans		Value of Unvested Performance Shares From Current Grant		Company Paid Term Life Insurance Premiums		Total
John W. Rowe	$	62,500	$	3,299,293	$	300,350	$	3,662,143
John L. Skolds		30,190		812,850		56,397		899,437
Randall E. Mehrberg		26,646		406,396		37,863		470,905
John F. Young		26,981		—		35,025		62,006
Frank M. Clark		20,846		573,790		71,527		666,163

	Option Grants for 2005
	Individual Grants
	Number of Securities Underlying Options Granted (#)	Percentage of Total Options Granted to Employees in 2005 (%)		Exercise or Base Price ($ /Share)		Options Expiration Date	Grant Date Present Value (See Note 1) ($)
John W. Rowe	229,000	4.3	%	$	42.85	01/23/2015	$	1,447,280
John L. Skolds	56,000	1.1	%		42.85	01/23/2015		353,920
Randall E. Mehrberg	56,000	1.1	%		42.85	01/23/2015		353,920
John F. Young	56,000	1.1	%		42.85	01/23/2015		353,920
Frank M. Clark	36,000	0.7	%		42.85	01/23/2015		227,520

1. The “grant date present values” indicated in the Option Grants Table are estimates 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 of the option on the date that the options are exercised. There is no certainty that the 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 grants, January 26, 2005, and are as follows: Risk free interest rate: 3.82%; Volatility: 18.1%; Dividend Yield: 3.6%; and time of exercise: 6.25 years.

	Option Exercises & Year End Value
	As of December 31, 2005 (See Note 1)
	Number of Shares Acquired by Exercise (Note 2) #	Dollar Value Realized From Exercise (Note 2)		Number of Securities Underlying Remaining Options		Dollar Value of In-the-Money Options
				Exercisable #	Unexercisable #	Exercisable		Unexercisable
John W. Rowe	557,500	$	17,731,757	1,637,444	704,000	$	39,447,136	$	13,495,035
John L. Skolds	187,500		4,259,206	122,500	156,000		3,148,800		2,945,640
Randall E. Mehrberg	123,600		2,660,892	70,400	152,000		1,464,856		2,832,300
John F. Young	—		—	28,500	111,500		705,750		1,838,190
Frank M. Clark	94,500		2,052,549	118,666	103,500		3,164,977		1,969,785

1. This table shows the number and value of exercisable and unexercisable stock options for the named executive officers during 2005. The value is determined using the closing market price of Exelon common stock on December 31, 2005, which was $53.14, less the exercise price of the options. All options whose exercise price exceeded the market price at the day of determination are valued at zero. For all data above, the number of shares and exercise prices have been adjusted to reflect the 2 for 1 stock split of May 5, 2004.

2. The value shown in this column is the gross proceeds from the exercise and sale which is the number of shares sold multiplied by the spread between sale price of the shares and the option strike price. This figure does not reflect any taxes or brokerage fees. All options exercised by the named executive officers during 2005 were done in accordance with Rule 10b5-1 Trading Plans, which were entered into at such time when the officer was unaware of any material adverse information in regard to current and prospective operations of Exelon which had not been publicly disclosed. The dates of the sales were set at the time the Trading Plans were established. Of the total number of shares exercised during 2005 by Mr. Rowe, he retained 93,201 shares.

435

Long-Term Incentive Plans—Awards in Last Fiscal Year

	Number of Shares, Units or Other Rights (See Note 1) (#)	Performance Period until Maturation or Payout.	Estimated future payouts under non-stock price-based plans (See Note 2)
			Threshold (#)	Target (#)	Maximum (#)
John W. Rowe	N/A	3 years	34,500	69,000	138,000
John L. Skolds	N/A	3 years	8,500	17,000	34,000
Randall E. Mehrberg	N/A	3 years	8,500	17,000	34,000
John F. Young	N/A	3 years	8,500	17,000	34,000
Frank M. Clark	N/A	3 years	6,000	12,000	24,000

1. Exelon’s Long Term Performance Share Award program under the Long-Term Incentive Plan provides incentives to key executives in the form of restricted stock and cash. Awards are determined upon the successful completion of strategic goals designed to achieve long term business success and increased shareholder value. These goals include Exelon’s Total Shareholder Return (TSR) over the previous three years relative to established benchmarks including a peer group of companies listed on the Dow Jones Utility Index (weighted 50%) and the Standard & Poor’s 500 Index (weighted 20%) and a quantifiable cash savings goal aligned with The Exelon Way initiative (weighted 30%). Grants under the Long Term Performance Share Award Program for 2005 are reflected in the Summary Compensation Table. See note 2 to that table

2. A target number of performance shares is established for each participant which is commensurate with the participant’s base salary. Based on measured performance as described above, participants may earn up to 200% of their target and may earn nothing if thresholds are not met.

ComEd Directors

ComEd

For their service as directors of the company, ComEd’s non-employee directors receive a $1,500 meeting fee for each board and committee meeting attended, whether in person or by means of teleconferencing or video conferencing equipment. All meeting fees are paid in cash. Employee directors receive no additional compensation for service as a director. Directors are also reimbursed for their reasonable travel and lodging expenses when attending ComEd board and committee meetings.

	Board Meeting Fees		Committee Meeting Fees	Total Compensation
Sue L. GIn	$	3,000	—	$	3,000
Edgar D. Jannotta		3,000	—		3,000
John W. Rogers, Jr.		3,000	—		3,000
Richard L. Thomas		3,000	—		3,000
Total	$	12,000	—	$	12,000

436

Executive Compensation

The compensation shown for some executives in the following Summary Compensation table is also included in the Summary Compensation tables for other Registrants.

Summary Compensation Table

		Annual Compensation						Long Term Compensation
Name and Principal Position	Year	Salary		Bonus		Other Annual Compensation (See Note 1)		Restricted Stock Award (See Notes 2 and 3)		Number of Options (See Note 4) #	Payouts (See Notes 2 and 5)		All Other Compensation (See Notes 2 and 6)
John L. Skolds	2005	$	603,808	$	509,998	$	34,126	$	—	56,000	$	406,454	$	899,437
Chairman & CEO, ComEd (through 11/25/2005)	2004 2003		571,154 530,673		462,239 393,837		3,472 2,762		739,118 634,530	80,000 80,000		426,400 —		513,883 64,276
Frank M. Clark	2005		416,923		341,591		48,409		—	36,000		286,895		666,163
Chairman & CEO, ComEd	2004 2003		402,596 377,404		275,367 227,880		8,355 9,427		626,927 444,171	54,000 54,000		293,151 —		377,067 67,432
J. Barry Mitchell	2005		378,108		320,276		38,106		427,944	21,000		167,336		244,542
President, ComEd	2004 2003		343,058 350,288		223,110 164,317		3,269 2,884		176,853 222,053	30,000 30,000		186,555 —		250,532 52,386
Robert K. McDonald	2005		277,116		212,231		18,769		356,221	14,000		95,612		126,213
Senior Vice President & CFO, ComEd	2004 2003		246,298 216,029		181,333 117,291		—   2,133		108,649 164,002	18,000 17,000		114,595 —		142,829 22,038
John T. Costello	2005		311,923		166,405		13,679		356,221	14,000		95,612		142,876
Executive Vice President & COO, ComEd	2004 2003		265,678 274,954		148,442 143,964		—   —		275,891 164,002	20,000 18,000		117,252 —		159,480 36,597
John T. Hooker	2005		240,031		131,381		23,214		88,528	13,000		88,469		119,062
Senior Vice President, Legislative & Governmental Affairs	2004 2003		237,608 224,817		101,813 100,446		576 5,214		101,074 164,002	17,000 18,000		106,597 —		138,044 25,353
John W. Rowe	2005		1,250,000		1,642,266		181,134		—	229,000		1,649,646		3,662,143
Chairman, President & CEO, Exelon	2004 2003		1,241,346 1,185,289		1,675,000 1,400,000		185,541 176,402		1,480,279 2,733,360	400,000 350,000		1,666,322 —		2,153,432 191,851
Ruth Ann M. Gillis	2005		400,000		308,700		47,880		286,895	36,000		286,895		323,400
Executive Vice President, ComEd (Through 09/30/2005)	2004 2003		388,029 364,471		321,158 263,123		6,612 7,230		277,927 444,171	54,000 54,000		293,151 —		344,872 35,319

437

Notes to Summary Compensation Table

1. The amounts shown under the column labeled “Other Annual Compensation” include perquisites and amounts reimbursed for the payment of income taxes. Executive officers receive certain perquisites commensurate with their position. The amounts for such perquisites and their description are as follows:

	Personal and Spouse Travel		Automobile Lease and Parking		Financial, Estate and Tax Planning Services		Dining, Health and Airline Club Member- ships		Other Items		Reimburse- ment for Payment of Taxes		Total
John L. Skolds	$	2,060	$	15,517	$	10,240	$	2,370	$	439	$	3,500	$	34,126
Frank M. Clark		962		33,339		—		6,740		1,386		5,982		48,409
J. Barry Mitchell		1,331		23,201		9,195		2,105		—		2,274		38,106
Robert K. McDonald		—		18,769		—		—		—		—		18,769
John T. Costello		—		13,679		—		—		—		—		13,679
John T. Hooker		—		23,214		—		—		—		—		23,214
John W. Rowe		102,617		19,116		15,591		10,114		14,400		19,296		181,134
Ruth Ann M. Gillis		979		21,944		12,871		6,320		—		5,766		47,880

Personal and Spouse Travel:Mr. Rowe is entitled to 50 hours of personal use of corporate aircraft. The figure shown in the table above includes $100,481 representing the aggregate incremental cost to Exelon for Mr. Rowe’s personal use of company aircraft. For 2005 this cost was calculated using the hourly cost for flight services paid to the aircraft vendor, Federal excise tax, fuel charges, and domestic segment fees. In previous reports the cost of personal use of corporate aircraft for 2004 and 2003 included an allocation of fixed costs and allocated overhead that would have been incurred regardless of personal use of the aircraft. For Mr. Rowe, the amounts shown in this column in the Summary Compensation Table for 2004 and 2003 have been restated for comparability with the aggregate incremental cost approach used for 2005. From time to time Mr. Rowe’s spouse accompanies Mr. Rowe in his travel on company aircraft. The aggregate incremental cost to the company, if any, for Mrs. Rowe’s personal use of company aircraft is included in the table. For all executive officers, including Mr. Rowe, Exelon pays the cost of their spouse’s travel, meals, and other related amenities when they attend company or industry related events where it is customary and expected that officers attend with their spouses. The aggregate incremental cost to Exelon for these expenses is included in the table. In most cases there is no incremental cost to Exelon of providing transportation or other amenities for a spouse, and the only additional cost to Exelon is to reimburse officers for the taxes on the imputed income attributable to their spouse’s travel, meals, and related amenities when attending company or industry related events. This cost is included in the column headed “Reimbursement for Payment of Taxes.”

Automobile Lease and Parking: Exelon provides officers with company vehicles, pays for insurance, maintenance, applicable taxes and provides a company paid credit card for fuel purchases. Where required, such as in downtown Chicago, officers also receive company paid parking. The figure shown in the table is the total cost of all automobile costs to the officer. For the named executive officers as a group a substantial majority of automobile use is for business purposes.

Financial, Estate, and Tax Planning Services: Officers may use any of these services through company-arranged vendors where the company pays for the service, or a vendor of their own choosing, for which the company will reimburse the officer for all reasonable expenses.

Dining, Health, and Airline Club Memberships:Officers are entitled to club memberships in each of the categories shown for the purpose of conducting business on behalf of the company. Membership in country clubs is not provided or reimbursed. The amounts shown represent only the payment of membership dues, variables costs for meals and other amenities are the responsibility of each named officer. When any variable costs are business related, Exelon will reimburse the officer directly for such costs. A substantial majority of club use is for business purposes.

Other Items: Executive officers may use company provided vendors for comprehensive physical examinations and related follow-up testing. Exelon maintains several cars and company drivers to provide chauffeur services to executive officers for business purposes. Mr. Rowe is entitled to limited personal use of a company driver including for commuting purposes when in Chicago which enables him to perform work for the company while commuting. Mr. Clark is also entitled to limited personal use of company drivers. The aggregate incremental cost for Exelon to provide limited personal trips included in the table is estimated based on driver overtime, when applicable, and fuel cost.

Reimbursement for Payment of Taxes: Officers receive a reimbursement to cover applicable taxes on imputed amounts for business related spousal travel, certain club memberships and relocation.

2. Exelon has a performance share award program under its Long Term Incentive Plan. Awards made prior to January 2005 were made in restricted stock that vested one-third upon the grant date and one-third upon each of the first and second anniversaries of the grant date. Beginning with awards made in January 2005 and for amounts vesting in 2005 and later, if

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the participant has achieved at least 125% of the participant’s stock ownership requirement, the performance shares are settled one-half in cash and one half in stock, with the same vesting schedule as before. Beginning with awards made in January 2006 and for amounts vesting in 2006, if the participant is an executive vice president or higher and has achieved more than 200% of the participant’s stock ownership requirement, the performance shares are settled entirely in cash.

For the 3 year performance period ended December 31, 2005, the named executive officers received performance share grants as shown in the following table; the shares were valued at $58.55, the NYSE closing price on January 23, 2006. The portion of the grants that will be settled in stock and will vest on the first and second anniversaries of the award is shown in column [C] below and in the column headed “Restricted Stock Awards” in the Summary Compensation Table above. The portion of the grants that vest immediately and is paid out in either cash or stock is shown in column [D] below and in the column headed “Long Term Compensation—Payouts” in the Table above. The remaining portion of the grants that may be settled in stock or cash (depending on the participant’s stock ownership on the relevant ownership measurement date is shown in column [E] below and in the column headed “All Other Compensation” in the Table above.

	[A] Number of Performance Shares #	[B] Total Value of Performance Share Award @ $58.55 / sh		[C] Value of Restricted Shares		[D] Value of Immediate Payout Settled in Cash or Shares		[E] Value of Future Payouts to be Settled in Cash or Shares
John L. Skolds	20,825	$	1,219,304	$	—	$	406,454	$	812,850
Frank M. Clark	14,700		860,685		—		286,895		573,790
J. Barry Mitchell	8,575		502,066		167,394		167,336		167,336
Robert K. McDonald	4,900		286,895		95,671		95,612		95,612
John T. Costello	4,900		286,895		95,671		95,612		95,612
John T. Hooker	4,533		265,407		88,528		88,469		88,410
John W. Rowe	84,525		4,948,939		—		1,649,646		3,299,293
Ruth Ann M. Gillis	14,700		860,685		286,895		286,895		286,895

3. This column reports the value of the restricted stock portion of performance share awards described above in Note 2 as well as other restricted awards granted to individuals during the preceding year by the Compensation Committee and the Board of Directors in recognition of specific accomplishments and/or significant increases in job responsibilities. Mssrs. Costello, McDonald, and Mitchell each received a grant of 5,000 restricted shares on November 28, 2005. These were valued at $52.11 per share and will vest on the fifth anniversary of the grant date. The named officers will earn regular dividends on the shares during this period.

The named executive officers held the amounts of restricted shares, including unvested performance shares granted with respect to the three-year performance periods ending December 31, 2004 and December 31, 2003 as shown in column [A] below. Unvested restricted and performance shares continue to receive dividends.

Columns [C] and [D] in the following table include the amounts and value of restricted and unvested performance shares that were distributed and settled on January 23, 2006. This includes the first third of the current grant for the three-year period ending December 31, 2005, that is shown above in Note 2, as well as the second third of those shares granted with respect to the 3-year performance period ending December 31, 2004 and the last third of those shares granted with respect to the three-year performance period ended December 31, 2003. The shares are valued at the closing price of Exelon stock on January 23, 2006 which was $58.55. The value of this distribution and settlement is not included in the Summary Compensation Table.

Columns [E] and [F] show the amount and total value of the restricted shares and unvested performance shares remaining after the distribution and settlement as of January 23, 2006. The shares are valued at $58.55.

	[A] Number of Restricted Shares and Unvested Performance Shares as of 12/31/2005 #	[B] Number of Performance Shares Granted on 01/23/2006 #	[C] Number of Performance Shares That Were Vested and Settled on 01/23/2006 #	[D] Value of Performance Shares That Were Vested and Settled on 01/23/2006 $58.55 / sh		[E] Remaining Number of Restricted and Unvested Performance Shares [A] + [B] – [C] #	[F] Total Value of Remaining Shares Shown in Column [E] as of 01/23/2006 $58.55 / sh
John L. Skolds	46,725	20,825	24,145	$	1,413,707	43,405	$	2,541,363
Frank M. Clark	28,972	14,700	16,814		984,473	26,858		1,572,536
J. Barry Mitchell	31,411	8,575	9,778		572,482	30,208		1,768,678
Robert K. McDonald	22,113	4,900	5,988		350,576	21,025		1,231,014
John T. Costello	17,380	4,900	6,190		362,445	16,090		942,070
John T. Hooker	16,728	4,533	5,673		332,138	15,588		912,677
John W. Rowe	110,123	84,525	98,178		5,748,343	96,470		5,648,319
Ruth Ann M. Gillis	18,972	14,700	16,814		984,473	16,858		987,036

4. Options granted prior to May 5, 2004 reflect the effect of a 2 for 1 stock split as of that date.

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5. The amounts shown under the column labeled “All Other Compensation” include company paid matching contributions to qualified and non-qualified savings plans along with the value of the unvested two-thirds of the performance share award granted with respect to the three-year performance period ending December 31, 2005 which will be paid out in cash or stock at the time of vesting in 2007 and 2008, depending upon the participants’ stock ownership at that time.

	Value of Company Contributions to Savings Plans		Value of Unvested Performance Shares From Current Grant		Company Paid Term Life Insurance Premiums		Total
John L. Skolds	$	30,190	$	812,850	$	56,397	$	899,437
Frank M. Clark		20,846		573,790		71,527		666,163
J. Barry Mitchell		18,906		167,394		58,242		244,542
Robert K. McDonald		13,856		95,671		16,686		126,213
John T. Costello		15,596		95,671		31,609		142,876
John T. Hooker		7,100		88,528		23,434		119,062
John W. Rowe		62,500		3,299,293		300,350		3,662,143
Ruth Ann M. Gillis		15,385		286,895		21,120		323,400

	Option Grants for 2005
	Individual Grants
	Number of Securities Underlying Options Granted (#)	Percentage of Total Options Granted to Exelon Employees in 2005 (%)		Exercise or Base Price ($ / Share)		Options Expiration Date	Grant Date Present Value (See Note 1) ($)
John L. Skolds	56,000	1.1	%	$	42.85	1/23/2015	$	353,920
Frank M. Clark	36,000	0.7	%		42.85	1/23/2015		227,520
J. Barry Mitchell	21,000	0.4	%		42.85	1/23/2015		132,720
Robert K. McDonald	14,000	0.3	%		42.85	1/23/2015		88,480
John T. Costello	14,000	0.3	%		42.85	1/23/2015		88,480
John T. Hooker	13,000	0.2	%		42.85	1/23/2015		82,160
John W. Rowe	229,000	4.3	%		42.85	1/23/2015		1,447,280
Ruth Ann M. Gillis	36,000	0.7	%		42.85	1/23/2015		227,520

1. The “grant date present values” indicated in the Option Grants Table are estimates 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 of the option on the date that the options are exercised. There is no certainty that the 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 grants, January 26, 2005, and are as follows: Risk free interest rate: 3.82%; Volatility: 18.1%; Dividend Yield: 3.6%; and time of exercise: 6.25 years.

	Option Exercises & Year End Value
	As of December 31, 2005 (See Note 1)
	Number of Shares Acquired by Exercise (Note 2) (#)	Dollar Value Realized From Exercise (Note 2)		Number of Securities Underlying Remaining Options		Dollar Value of In-the-Money Options
				Exercisable (#)	Unexercisable (#)	Exercisable		Unexercisable
John L. Skolds	187,500	$	4,259,206	122,500	156,000	$	3,148,800	$	2,945,640
Frank M. Clark	94,500		2,052,549	118,666	106,500		3,164,977		1,969,785
J. Barry Mitchell	72,600		2,004,287	52,500	58,500		1,469,925		1,104,615
Robert K. McDonald	37,000		742,788	—	36,000		—		663,008
John T. Costello	17,833		410,601	—	38,000		—		708,075
John T. Hooker	17,804		392,478	—	34,750		—		651,435
John W. Rowe	557,500		17,731,757	1,637,444	704,000		39,447,136		13,495,035
Ruth Ann M. Gillis	155,000		4,078,370	176,500	103,500		4,287,085		1,969,785

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1. This table shows the number and value of exercisable and unexercisable stock options for the named executive officers during 2005. The value is determined using the closing market price of Exelon common stock on December 31, 2005, which was $53.14, less the exercise price of the options. All options whose exercise price exceeded the market price at the day of determination are valued at zero. For all data above, the number of shares and exercise prices have been adjusted to reflect the 2 for 1 stock split of May 5, 2004.

2. The value shown in this column is the gross proceeds from the exercise and sale which is the number of shares sold multiplied by the spread between sale price of the shares and the option strike price. This figure does not reflect any taxes or brokerage fees. All options exercised by Messrs. Skolds, Clark, Mitchell, Rowe, and Ms. Gillis during 2005 were done in accordance with Rule 10b5-1 Trading Plans, which were entered into at such time when the officer was unaware of any material adverse information in regard to current and prospective operations of Exelon which had not been publicly disclosed. The dates of the sales were set at the time the Trading Plans were established. Of the total number of shares exercised during 2005 by Mr. Rowe, he retained 93,201 shares.

Long-Term Incentive Plans—Awards in Last Fiscal Year

	Number of Shares, Units or Other Rights (See Note 1) (#)	Performance Period until Maturation or Payout.	Estimated future payouts under non-stock price-based plans (See Note 2)
			Threshold (#)	Target (#)	Maximum (#)
John L. Skolds	N/A	3 years	8,500	17,000	34,000
Frank M. Clark	N/A	3 years	6,000	12,000	24,000
J. Barry Mitchell	N/A	3 years	3,500	7,000	14,000
Robert K. McDonald	N/A	3 years	2,000	4,000	8,000
John T. Costello	N/A	3 years	2,000	4,000	8,000
John T. Hooker	N/A	3 years	1,850	3,700	7,400
John W. Rowe	N/A	3 years	34,500	69,000	138,000
Ruth Ann M. Gillis	N/A	3 years	6,000	12,000	24,000

1. Exelon’s Long Term Performance Share Award program under the Long-Term Incentive Plan provides incentives to key executives in the form of restricted stock and cash. Awards are determined upon the successful completion of strategic goals designed to achieve long term business success and increased shareholder value. These goals include Exelon’s Total Shareholder Return (TSR) over the previous three years relative to established benchmarks including a peer group of companies listed on the Dow Jones Utility Index (weighted 50%) and the Standard & Poor’s 500 Index (weighted 20%) and a quantifiable cash savings goal aligned with The Exelon Way initiative (weighted 30%). Grants under the Long Term Performance Share Award Program for 2005 are reflected in the Summary Compensation Table. See note 2 to that table

2. A target number of performance shares is established for each participant which is commensurate with the participant’s base salary. Based on measured performance as described above, participants may earn up to 200% of their target and may earn nothing if thresholds are not met.

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PECO

Executive Compensation

The compensation shown for some executives in the following Summary Compensation table is also included in the Summary Compensation tables for other Registrants.

Summary Compensation Table

		Annual Compensation						Long Term Compensation
Name and Principal Position	Year	Salary		Bonus		Other Annual Compensation (See Note 1)		Restricted Stock Award (See Notes 2 and 3)		Number of Options (See Note 4) #	Payouts (See Notes 2 and 5)		All Other Compensation (See Notes 2 and 6)
John L. Skolds	2005	$	603,808	$	509,998	$	34,126	$	—	56,000	$	406,454	$	899,437
Executive Vice President, Exelon Corp. President, Exelon Energy Delivery	2004 2003		571,154 530,673		462,239 393,837		3,472 2,762		739,118 634,530	80,000 80,000		426,400 —		513,883 64,276
John W. Rowe	2005		1,250,000		1,642,266		181,134		—	229,000		1,649,646		3,662,143
Chairman, President & Chief Executive Officer, Exelon Corp.	2004 2003		1,241,346 1,185,289		1,675,000 1,400,000		185,541 176,402		1,480,279 2,733,360	400,000 350,000		1,666,322 —		2,153,432 191,851
John F. Young	2005		539,615		443,113		238,872		812,850	56,000		406,454		62,006
Executive Vice President & Chief Financial Officer, Exelon Corp	2004 2003		435,807 311,923		505,680 214,159		5,066 144,943		330,695 494,236	54,000 30,000		348,842 —		415,106 185,973
Denis P. O’Brien	2005		371,769		270,745		26,928		191,224	29,000		191,283		230,809
President, PECO Energy Co.	2004 2003		344,498 296,154		238,873 194,897		5,570 450		202,106 285,896	40,000 30,000		213,193 —		260,141 33,462
Matthew F. Hilzinger	2005		292,532		222,843		20,228		95,671	14,000		95,612		110,756
Senior Vice President and Corp. Controller, Exelon Corp.	2004 2003		279,596 268,683		209,710 139,242		277 1,833		390,341 145,909	18,000 17,000		117,252 —		136,260 13,434
J. Barry Mitchell	2005		378,108		320,276		38,106		427,944	21,000		167,336		244,542
CFO and Treasurer, PECO Energy Co. (through 11/28/2005)	2004 2003		343,058 350,288		223,110 164,317		3,269 2,884		176,853 222,053	30,000 30,000		186,555 —		250,532 52,386

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Notes to Summary Compensation Table

1. The amounts shown under the column labeled “Other Annual Compensation” include perquisites and amounts reimbursed for the payment of income taxes. Executive officers receive certain perquisites commensurate with their position. The amounts of such perquisites and their description are as follows:

	Personal and Spouse Travel		Automobile Lease and Parking		Financial, Estate and Tax Planning Services		Dining, Health and Airline Club Member- ships		Other Items		Reimbursement for Payment of Taxes		Total
John L. Skolds	$	2,060	$	15,517	$	10,240	$	2,370	$	439	$	3,500	$	34,126
John W. Rowe		102,617		19,116		15,591		10,114		14,400		19,296		181,134
John F. Young		3,855		17,955		22,306		1,395		156,696		36,665		238,872
Denis P. O’Brien		1,775		15,153		500		2,862		3,225		3,467		26,982
Matthew F. Hilzinger		—		20,228		—		—		—		—		20,228
J. Barry Mitchell		1,331		23,201		9,195		2,105		—		2,274		38,106

Personal and Spouse Travel:Mr. Rowe is entitled to 50 hours of personal use of corporate aircraft. The figure shown in the table above includes $100,481 representing the aggregate incremental cost to Exelon for Mr. Rowe’s personal use of company aircraft. For 2005 this cost was calculated using the hourly cost for flight services paid to the aircraft vendor, Federal excise tax, fuel charges, and domestic segment fees. In previous reports the cost of personal use of corporate aircraft for 2004 and 2003 included an allocation of fixed costs and allocated overhead that would have been incurred regardless of personal use of the aircraft. For Mr. Rowe, the amounts shown in this column in the Summary Compensation Table for 2004 and 2003 have been restated for comparability with the aggregate incremental cost approach used for 2005. From time to time Mr. Rowe’s spouse accompanies Mr. Rowe in his travel on company aircraft. The aggregate incremental cost to the company, if any, for Mrs. Rowe’s personal use of company aircraft is included in the table. For all executive officers, including Mr. Rowe, Exelon pays the cost of their spouse’s travel, meals, and other related amenities when they attend company or industry related events where it is customary and expected that officers attend with their spouses. The aggregate incremental cost to Exelon for these expenses is included in the table. In most cases there is no incremental cost to Exelon of providing transportation or other amenities for a spouse, and the only additional cost to Exelon is to reimburse officers for the taxes on the imputed income attributable to their spouse’s travel, meals, and related amenities when attending company or industry related events. This cost is included in the column headed “Reimbursement for Payment of Taxes.”

Automobile Lease and Parking: Exelon provides officers with company vehicles, pays for insurance, maintenance, applicable taxes and provides a company paid credit card for fuel purchases. Where required, such as in downtown Chicago, officers also receive company paid parking. The figure shown in the table is the total cost of all automobile costs to the officer. For the named executive officers as a group a substantial majority of automobile use is for business purposes.

Financial, Estate, and Tax Planning Services: Officers may use any of these services through company-arranged vendors where the company pays for the service, or a vendor of their own choosing, for which the company will reimburse the officer for all reasonable expenses.

Dining, Health, and Airline Club Memberships:Officers are entitled to club memberships in each of the categories shown for the purpose of conducting business on behalf of the company. Membership in country clubs is not provided or reimbursed. The amounts shown represent only the payment of membership dues, variables costs for meals and other amenities are the responsibility of each named officer. When any variable costs are business related, Exelon will reimburse the officer directly for such costs. A substantial majority of club use is for business purposes.

Other Items: Executive officers may use company provided vendors for comprehensive physical exams and related follow-up testing. Exelon maintains several cars and company drivers to provide chauffeur services to executive officers for business purposes. Mr. Rowe is entitled to limited personal use of a company driver including for commuting purposes when in Chicago which enables him to perform work for the company while commuting. Mr. O’Brien is also entitled to limited personal use of company drivers. The aggregate incremental cost for Exelon to provide limited personal trips included in the table is estimated based on driver overtime, when applicable, and fuel cost. For Mr. Young, the value shown in the table includes a $100,000 relocation bonus and a moving allowance to relocate to the Chicago area.

Reimbursement for Payment of Taxes: Officers receive a reimbursement to cover applicable taxes on imputed amounts for business related spousal travel, certain club memberships, and relocation expenses. For Mr. Young the amount shown includes $32,624 for payment of taxes on his imputed relocation expense.

2. Exelon has a performance share award program under its Long Term Incentive Plan. Awards made prior to January 2005 were made in restricted stock that vested one-third upon the grant date and one-third upon each of the first and second

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anniversaries of the grant date. Beginning with awards made in January 2005 and for amounts vesting in 2005 and later, if the participant has achieved at least 125% of the participant’s stock ownership requirement, the performance shares are settled one-half in cash and one half in stock, with the same vesting schedule as before. Beginning with awards made in January 2006 and for amounts vesting in 2006, if the participant is an executive vice president or higher and has achieved more than 200% of the participant’s stock ownership requirement, the performance shares are settled entirely in cash.

For the 3 year performance period ended December 31, 2005, the named executive officers received performance share grants as shown in the following table; the shares were valued at $58.55, the NYSE closing price on January 23, 2006. The portion of the grants that will be settled in stock and will vest on the first and second anniversaries of the award is shown in column [C] below and in the column headed “Restricted Stock Awards” in the Summary Compensation Table above. The portion of the grants that vest immediately and is paid out in either cash or stock is shown in column [D] below and in the column headed “Long Term Compensation—Payouts” in the Table above. The remaining portion of the grants that may be settled in stock or cash (depending on the participant’s stock ownership on the relevant ownership measurement date) is shown in column [E] below and in the column headed “All Other Compensation” in the Table above.

	[A] Number of Performance Shares (#)	[B] Total Value of Performance Share Award		[C] Value of Restricted Shares		[D] Value of Immediate Payout Settled in Cash or Shares		[E] Value of Future Payouts to be Settled in Cash or Shares
John L. Skolds	20,825	$	1,219,304	$	—	$	406,454	$	812,850
John W. Rowe	84,525		4,948,939		—		1,649,646		3,299,293
John F. Young	20,825		1,219,304		812,850		406,454		—
Denis P. O’Brien	9,800		573,790		191,224		191,283		191,283
Matthew F. Hilzinger	4,900		286,895		95,671		95,612		95,612
J. Barry Mitchell	8,575		502,066		167,394		167,336		167,336

3. This column reports the value of the restricted stock portion of performance share awards described above in Note 2 as well as other restricted awards granted to individuals during the preceding year by the Compensation Committee and the Board of Directors in recognition of specific accomplishments and/or significant increases in job responsibilities. Mr. Mitchell received a grant of 5,000 restricted shares on November 28, 2005. These were valued at $52.11 per share and will vest on the fifth anniversary of the grant date. Mr. Mitchell will earn regular dividends on the shares during this period.

The named executive officers held the amounts of restricted shares, including unvested performance shares granted with respect to the three-year performance periods ending December 31, 2004 and December 31, 2003 as shown in column [A] below. Unvested restricted and performance shares continue to receive dividends.

Columns [C] and [D] in the following table include the amounts and value of restricted and unvested performance shares that were distributed and settled on January 23, 2006. This includes the first third of the current grant for the three-year period ending December 31, 2005, that is shown above in Note 2, as well as the second third of those shares granted with respect to the 3-year performance period ending December 31, 2004 and the last third of those shares granted with respect to the three-year performance period ended December 31, 2003. The shares are valued at the closing price of Exelon stock on January 23, 2006 which was $58.55. The value of this distribution and settlement is not included in the Summary Compensation Table.

Columns [E] and [F] show the amount and total value of the restricted shares and unvested performance shares remaining after the distribution and settlement as of January 23, 2006. The shares are valued at $58.55.

	[A] Number of Restricted Shares and Unvested Performance Shares as of 12/31/2005 (#)	[B] Number of Performance Shares Granted on 01/23/2006 (#)	[C] Number of Performance Shares That Were Vested and Settled on 01/23/2006 (#)	[D] Value of Performance Shares That Were Vested and Settled on 01/23/2006 $58.55 / sh		[E] Remaining Number of Restricted and Unvested Performance Shares [A] + [B] – [C] (#)	[F] Total Value of Remaining Shares Shown in Column [E] as of 01/23/2006 $58.55 / sh
John L. Skolds	46,725	20,825	24,145	$	1,413,707	43,405	$	2,541,363
John W. Rowe	110,123	84,525	98,178		5,748,343	96,470		5,648,319
John F. Young	25,855	20,825	19,398		1,135,737	27,282		1,597,361
Denis P. O’Brien	13,392	9,800	11,525		674,810	11,667	$	683,103
Matthew F. Hilzinger	15,241	4,900	6,052		354,321	14,089	$	824,911
J. Barry Mitchell	31,411	8,575	9,778		572,482	30,208		1,768,678

4. Options granted prior to May 5, 2004 reflect the effect of a 2 for 1 stock split as of that date.

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5. The amounts shown under the column labeled “All Other Compensation” include company paid matching contributions to qualified and non-qualified savings plans along with the value of the unvested two-thirds of the performance share award granted with respect to the three-year performance period ending December 31, 2005 which will be paid out in cash or stock at the time of vesting in 2007 and 2008, depending upon the participants’ stock ownership at that time.

	Value of Company Contributions to Savings Plans		Value of Unvested Performance Shares From Current Grant		Company Paid Term Life Insurance Premiums		Total
John L. Skolds	$	30,190	$	812,850	$	56,397	$	899,437
John W. Rowe		62,500		3,299,293		300,350		3,662,143
John F. Young		26,981		—		35,025		62,006
Denis P. O’Brien		18,588		191,283		20,938		230,809
Matthew F. Hilzinger		14,627		95,612		517		110,756
J. Barry Mitchell		18,906		167,394		58,242		244,542

	Option Grants for 2005
	Individual Grants
	Number of Securities Underlying Options Granted (#)	Percentage of Total Options Granted to Exelon Employees in 2005 (%)		Exercise or Base Price ($ / Share)		Options Expiration Date	Grant Date Present Value (See Note 1) ($)
John L. Skolds	56,000	1.1	%	$	42.85	01/23/2015	$	353,920
John W. Rowe	229,000	4.3	%		42.85	01/23/2015		1,447,280
John F. Young	56,000	1.1	%		42.85	01/23/2015		353,920
Denis P. O’Brien	29,000	0.5	%		42.85	01/23/2015		183,280
Matthew F. Hilzinger	14,000	0.3	%		42.85	01/23/2015		88,480
J. Barry Mitchell	21,000	0.4	%		42.85	01/23/2015		132,720

1. The “grant date present values” indicated in the Option Grants Table are estimates 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 of the option on the date that the options are exercised. There is no certainty that the 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 grants, January 26, 2005, and are as follows: Risk free interest rate: 3.82%; Volatility: 18.1%; Dividend Yield: 3.6%; and time of exercise: 6.25 years.

	Option Exercises & Year End Value
	As of December 31, 2005 (See Note 1)
	Number of Shares Acquired by Exercise (Note 2) (#)	Dollar Value Realized From Exercise (Note 2)		Number of Securities Underlying Remaining Options		Dollar Value of In-the-Money Options
				Exercisable (#)	Unexercisable (#)	Exercisable		Unexercisable
John L. Skolds	187,500	$	4,259,206	122,500	156,000	$	3,148,800	$	2,945,640
John W. Rowe	557,500		17,731,757	1,637,444	704,000		39,447,136		13,495,035
John F. Young	—		—	28,500	111,500		705,750		1,838,190
Denis P. O’Brien	69,000		1,344,491	56,000	74,000		1,893,609		1,341,435
Matthew F. Hilzinger	—		—	37,000	36,000		960,908		663,008
J. Barry Mitchell	72,600		2,004,287	52,500	58,500		1,469,925		1,104,615

1. This table shows the number and value of exercisable and unexercisable stock options for the named executive officers during 2005. The value is determined using the closing market price of Exelon common stock on December 31, 2005, which was $53.14, less the exercise price of the options. All options whose exercise price exceeded the market price at the day of determination are valued at zero. For all data above, the number of shares and exercise prices have been adjusted to reflect the 2 for 1 stock split of May 5, 2004.

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2. The value shown in this column is the gross proceeds from the exercise and sale which is the number of shares sold multiplied by the spread between sale price of the shares and the option strike price. This figure does not reflect any taxes or brokerage fees. All options exercised by Messrs. Skolds, Rowe, and Mitchell during 2005 were done in accordance with a Rule 10b5-1 Trading Plans, which were entered into at such time when the officer was unaware of any material adverse information in regard to current and prospective operations of Exelon which had not been publicly disclosed. The dates of the sales were set at the time the Trading Plan was established. Of the total number of shares exercised during 2005 by Mr. Rowe, he retained 93,201 shares.

Long-Term Incentive Plans—Awards in Last Fiscal Year

	Number of Shares, Units or Other Rights (See Note 1) (#)	Performance Period until Maturation or Payout.	Estimated future payouts under non-stock price-based plans (See Note 2)
			Threshold (#)	Target (#)	Maximum (#)
John L. Skolds	N/A	3 years	8,500	17,000	34,000
John W. Rowe	N/A	3 years	34,500	69,000	138,000
John F. Young	N/A	3 years	8,500	17,000	34,000
Denis P. O’Brien	N/A	3 years	4,000	8,000	16,000
Matthew F. Hilzinger	N/A	3 years	2,000	4,000	8,000
J. Barry Mitchell	N/A	3 years	3,500	7,000	14,000

1. Exelon’s Long Term Performance Share Award program under the Long-Term Incentive Plan provides incentives to key executives in the form of restricted stock and cash. Awards are determined upon the successful completion of strategic goals designed to achieve long term business success and increased shareholder value. These goals include Exelon’s Total Shareholder Return (TSR) over the previous three years relative to established benchmarks including a peer group of companies listed on the Dow Jones Utility Index (weighted 50%) and the Standard & Poor’s 500 Index (weighted 20%) and a quantifiable cash savings goal aligned with The Exelon Way initiative (weighted 30%). Grants under the Long Term Performance Share Award Program for 2005 are reflected in the Summary Compensation Table. See note 2 to that table.

2. A target number of performance shares is established for each participant which is commensurate with the participant’s base salary. Based on measured performance as described above, participants may earn up to 200% of their target and may earn nothing if thresholds are not met.

446

Generation

Executive Compensation

The compensation shown for some executives in the following Summary Compensation table is also included in the Summary Compensation tables for other Registrants.

Summary Compensation Table

		Annual Compensation						Long Term Compensation
Name and Principal Position	Year	Salary		Bonus		Other Annual Compensation (See Note 1)		Restricted Stock Award (See Notes 2 and 3)		Number of Options (See Note 4) #	Payouts (See Notes 2 and 5)		All Other Compensation (See Notes 2 and 6)
JohnL. Skolds	2005	$	603,808	$	509,998	$	34,126	$	—	56,000	$	406,454	$	899,437
Executive Vice President, Exelon Corp.; President, Exelon Generation	2004 2003		571,154 530,673		462,239 393,837		3,472 2,762		739,118 634,530	80,000 80,000		426,400 —		513,883 64,276
John F.Young	2005		539,615		443,113		238,872		812,850	56,000		406,454		62,006
Executive Vice President and Chief Financial Officer, Exelon Corp.; President, Exelon Generation through 02/23/2005	2004 2003		435,807 311,923		505,680 214,159		5,066 144,943		330,695 494,236	54,000 30,000		348,842 —		415,106 185,973
John W. Rowe	2005		1,250,000		1,642,266		181,134		—	229,000		1,649,646		3,662,143
Chairman, President & Chief Executive Officer, Exelon Corp.	2004 2003		1,241,346 1,185,289		1,675,000 1,400,000		185,541 176,402		1,480,279 2,733,360	400,000 350,000		1,666,322 —		2,153,432 191,851
Christopher M. Crane	2005		482,346		347,563		28,756		286,895	36,000		286,895		336,577
President, Exelon Nuclear and Chief Nuclear Officer	2004 2003		458,269 387,788		420,654 219,489		1,738 277		961,827 317,265	54,000 40,000		293,151 —		348,425 36,525
Ian P. McLean	2005		430,550		308,149		22,231		—	56,000		406,454		871,787
Executive Vice President, Exelon; President Exelon Power Team	2004 2003		427,438 411,827		407,705 273,607		3,076 9,657		404,218 634,530	80,000 72,000		426,400 —		506,844 57,511
Mark A. Schiavoni	2005		300,462		169,303		25,301		191,283	14,000		95,612		46,335
President, Exelon Power	2004 2003		245,319 224,423		221,127 117,921		10,972 136,304		105,263 98,141	21,000 18,600		111,039 —		130,030 11,221
J. Barry Mitchell	2005		378,108		320,276		38,106		427,944	21,000		167,336		244,542
CFO and Treasurer, Exelon Generation (through 11/28/2005)	2004 2003		343,058 350,288		223,110 164,317		3,269 2,884		176,853 222,053	30,000 30,000		186,555 —		250,532 52,386

447

Notes to Summary Compensation Table

1. The amounts shown under the column labeled “Other Annual Compensation” include perquisites and amounts reimbursed for the payment of income taxes. Executive officers receive certain perquisites commensurate with their position. The amounts for such perquisites and their description are as follows:

	Personal and Spouse Travel		Automobile Lease and Parking		Financial, Estate and Tax Planning Services		Dining, Health and Airline Club Member- ships		Other Items		Reimburse- ment for Payment of Taxes		Total
John L. Skolds	$	2,060	$	15,517	$	10,240	$	2,370	$	439	$	3,500	$	34,126
John F. Young		3,855		17,955		22,306		1,395		156,696		36,665		238,872
John W. Rowe		102,617		19,116		15,591		10,114		14,400		19,296		181,134
Christopher M. Crane		897		16,264		10,260		350		—		985		28,756
Ian P. McLean		2,384		17,337		—		350		—		2,160		22,231
Mark A. Schiavoni		—		23,530		—		420		1,019		332		25,301
J. Barry Mitchell		1,331		23,201		9,195		2,105		—		2,274		38,106

Personal and Spouse Travel:Mr. Rowe is entitled to 50 hours of personal use of corporate aircraft. The figure shown in the table above includes $100,481 representing the aggregate incremental cost to Exelon for Mr. Rowe’s personal use of company aircraft. For 2005 this cost was calculated using the hourly cost for flight services paid to the aircraft vendor, Federal excise tax, fuel charges, and domestic segment fees. In previous reports the cost of personal use of corporate aircraft for 2004 and 2003 included an allocation of fixed costs and allocated overhead that would have been incurred regardless of personal use of the aircraft. For Mr. Rowe, the amounts shown in this column in the Summary Compensation Table for 2004 and 2003 have been restated for comparability with the aggregate incremental cost approach used for 2005. From time to time Mr. Rowe’s spouse accompanies Mr. Rowe in his travel on company aircraft. The aggregate incremental cost to the company, if any, for Mrs. Rowe’s personal use of company aircraft is included in the table. For all executive officers, including Mr. Rowe, Exelon pays the cost of their spouse’s travel, meals, and other related amenities when they attend company or industry related events where it is customary and expected that officers attend with their spouses. The aggregate incremental cost to Exelon for these expenses is included in the table. In most cases there is no incremental cost to Exelon of providing transportation or other amenities for a spouse, and the only additional cost to Exelon is to reimburse officers for the taxes on the imputed income attributable to their spouse’s travel, meals, and related amenities when attending company or industry related events. This cost is included in the column headed “Reimbursement for Payment of Taxes.”

Automobile Lease and Parking: Exelon provides officers with company vehicles, pays for insurance, maintenance, applicable taxes and provides a company paid credit card for fuel purchases. Where required, such as in downtown Chicago, officers also receive company paid parking. The figure shown in the table is the total cost of all automobile costs to the officer. For the named executive officers as a group a substantial majority of automobile use is for business purposes.

Financial, Estate, and Tax Planning Services: Officers may use any of these services through company-arranged vendors where the company pays for the service, or a vendor of their own choosing, for which the company will reimburse the officer for all reasonable expenses.

Dining, Health, and Airline Club Memberships:Officers are entitled to club memberships in each of the categories shown for the purpose of conducting business on behalf of the company. Membership in country clubs is not provided or reimbursed. The amounts shown represent only the payment of membership dues, variables costs for meals and other amenities are the responsibility of each named officer. When any variable costs are business related, Exelon will reimburse the officer directly for such costs. A substantial majority of club use is for business purposes.

Other Items: Executive officers may use company provided vendors for comprehensive physical exams and related follow-up testing. Exelon maintains several cars and company drivers to provide chauffeur services to executive officers for business purposes. Mr. Rowe is entitled to limited personal use of a company driver including for commuting purposes when in Chicago which enables him to perform work for the company while commuting. The aggregate incremental cost for Exelon to provide limited personal trips included in the table is estimated based on driver overtime, when applicable, and fuel cost. For Mr. Young, the value shown in the table includes a $100,000 relocation bonus and a moving allowance to relocate to the Chicago area.

Reimbursement for Payment of Taxes: Officers receive a reimbursement to cover applicable taxes on imputed amounts for business related spousal travel, certain club memberships, and relocation expenses. For Mr. Young the amount shown includes $32,624 for payment of taxes on his imputed relocation expense.

448

2. Exelon has a performance share award program under its Long Term Incentive Plan. Awards made prior to January 2005 were made in restricted stock that vested one-third upon the grant date and one-third upon each of the first and second anniversaries of the grant date. Beginning with awards made in January 2005 and for amounts vesting in 2005 and later, if the participant has achieved at least 125% of the participant’s stock ownership requirement, the performance shares are settled one-half in cash and one half in stock, with the same vesting schedule as before. Beginning with awards made in January 2006 and for amounts vesting in 2006, if the participant is an executive vice president or higher and has achieved more than 200% of the participant’s stock ownership requirement, the performance shares are settled entirely in cash.

For the 3 year performance period ended December 31, 2005, the named executive officers received performance share grants as shown in the following table; the shares were valued at $58.55, the NYSE closing price on January 23, 2006. The portion of the grants that will be settled in stock and will vest on the first and second anniversaries of the award is shown in column [C] below and in the column headed “Restricted Stock Awards” in the Summary Compensation Table above. The portion of the grants that vest immediately and is paid out in either cash or stock is shown in column [D] below and in the column headed “Long Term Compensation—Payouts” in the Table above. The remaining portion of the grants that may be settled in stock or cash (depending on the participant’s stock ownership on the relevant ownership measurement date) is shown in column [E] below and in the column headed “All Other Compensation” in the Table above.

	[A] Number of Performance Shares (#)	[B] Total Value of Performance Share Award		[C] Value of Restricted Shares		[D] Value of Immediate Payout Settled in Cash or Shares		[E] Value of Future Payouts to be Settled in Cash or Shares
John L. Skolds	20,825	$	1,219,304	$	—	$	406,454	$	812,850
John F. Young	20,825		1,219,304		812,850		406,454		—
John W. Rowe	84,525		4,948,939		—		1,649,646		3,299,293
Christopher M. Crane	14,700		860,685		286,895		286,895		286,895
Ian P. McLean	20,825		1,219,304		—		406,454		812,850
Mark A. Schiavoni	4,900		286,895		191,283		95,612		—
J. Barry Mitchell	8,575		502,066		167,394		167,336		167,336

3. This column reports the value of the restricted stock portion of performance share awards described above in Note 2 as well as other restricted awards granted to individuals during the preceding year by the Compensation Committee and the Board of Directors in recognition of specific accomplishments and/or significant increases in job responsibilities. Mr. Mitchell received a grant of 5,000 restricted shares on November 28, 2005. These were valued at $52.11 per share and will vest on the fifth anniversary of the grant date. Mr. Mitchell were earn regular dividends on the shares during this period.

The named executive officers held the amounts of restricted shares, including unvested performance shares granted with respect to the three-year performance periods ending December 31, 2004 and December 31, 2003 as shown in column [A] below. Unvested restricted and performance shares continue to receive dividends.

449

Columns [C] and [D] in the following table include the amounts and value of restricted and unvested performance shares that were distributed and settled on January 23, 2006. This includes the first third of the current grant for the three-year period ending December 31, 2005, that is shown above in Note 2, as well as the second third of those shares granted with respect to the 3-year performance period ending December 31, 2004 and the last third of those shares granted with respect to the three-year performance period ended December 31, 2003. The shares are valued at the closing price of Exelon stock on January 23, 2006 which was $58.55. The value of this distribution and settlement is not included in the Summary Compensation Table.

Columns [E] and [F] show the amount and total value of the restricted shares and unvested performance shares remaining after the distribution and settlement as of January 23, 2006. The shares are valued at $58.55.

			Restricted & Unvested Performance Shares Remaining After 2005 Grants and Vesting on 01/24/2006
	[A] Number of Restricted Shares and Unvested Performance Shares as of 12/31/2005 (#)	[B] Number of Performance Shares Granted on 01/23/2006 (#)	[C] Number of Performance Shares That Were Vested and Settled on 01/23/2006 (#)	[D] Value of Performance Shares That Were Vested and Settled on 01/23/2006 $58.55 / sh		[E] Remaining Number of Restricted and Unvested Performance Shares [A] + [B] – [C] (#)	[F] Total Value of Remaining Shares Shown in Column [E] as of 01/23/2006 $58.55 / sh
John L. Skolds	46,725	20,825	24,145	$	1,413,707	43,405	$	2,541,363
John F. Young	25,855	20,825	19,398		1,135,737	27,282		1,597,361
John W. Rowe	110,123	84,525	98,178		5,748,343	96,470		5,648,319
Christopher M. Crane	37,585	14,700	15,427		903,278	36,858		2,158,036
Ian P. McLean	27,470	20,825	24,145		1,413,707	24,150		1,413,983
Mark A. Schiavoni	18,942	4,900	5,902		345,562	17,940		1,050,387
J. Barry Mitchell	31,411	8,575	9,778		572,482	30,208		1,768,678

4. Options granted prior to May 5, 2004 reflect the effect of a 2 for 1 stock split as of that date.

5. The amounts shown under the column labeled “All Other Compensation” include company paid matching contributions to qualified and non-qualified savings plans along with the value of the unvested two-thirds of the performance share award granted with respect to the three-year performance period ending December 31, 2005 which will be paid out in cash or stock at the time of vesting in 2007 and 2008, depending upon the participants’ stock ownership at that time.

	Value of Company Contributions to Savings Plans		Value of Unvested Performance Shares From Current Grant		Company Paid Term Life Insurance Premiums		Total
John L. Skolds	$	30,190	$	812,850	$	56,397	$	899,437
John F. Young		26,981		—		35,025		62,006
John W. Rowe		62,500		3,299,293		300,350		3,662,143
Christopher M. Crane		24,117		286,895		25,565		336,577
Ian P. McLean		21,500		812,850		37,437		871,787
Mark A. Schiavoni		15,023		—		31,312		46,335
J. Barry Mitchell		18,906		167,394		58,242		244,542

450

	Option Grants for 2005
	Individual Grants
	Number of Securities Underlying Options Granted (#)	Percentage of Total Options Granted to Exelon Employees in 2004 (%)		Exercise or Base Price ($ / Share)		Options Expiration Date	Grant Date Present Value (See Note 1) ($)
John L. Skolds	56,000	1.1	%	$	42.85	01/23/2015	$	353,920
John F. Young	56,000	4.3	%		42.85	01/23/2015		353,920
John W. Rowe	229,000	1.1	%		42.85	01/23/2015		1,447,280
Christopher M. Crane	36,000	0.7	%		42.85	01/23/2015		227,520
Ian P. McLean	56,000	1.1	%		42.85	01/23/2015		353,920
Mark A. Schiavoni	14,000	0.3	%		42.85	01/23/2015		88,480
J. Barry Mitchell	21,000	0.4	%		42.85	01/23/2015		132,720

1. The “grant date present values” indicated in the Option Grants Table are estimates 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 of the option on the date that the options are exercised. There is no certainty that the 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 grants, January 26, 2005, and are as follows: Risk free interest rate: 3.82%; Volatility: 18.1%; Dividend Yield: 3.6%; and time of exercise: 6.25 years.

	Option Exercises & Year End Value
	As of December 31, 2005 (See Note 1)
	Number of Shares Acquired by Exercise (Note 2) (#)	Dollar Value Realized From Exercise (Note 2)		Number of Securities Underlying Remaining Options		Dollar Value of In-the-Money Options
				Exercisable (#)	Unexercisable (#)	Exercisable ($)		Unexercisable ($)
John L. Skolds	187,500	$	4,259,206	122,500	156,000	$	3,148,800	$	2,945,640
John F. Young	—		—	28,500	111,500		705,750		1,838,190
John W. Rowe	557,500		17,731,757	1,637,444	704,000		39,447,136		13,495,035
Christopher M. Crane	211,500		3,698,865	—	96,500		—		1,771,440
Ian P. McLean	—		—	281,288	152,000		7,313,297		2,832,300
Mark A. Schiavoni	15,234		257,608	—	39,050		—		732,026
J. Barry Mitchell	72,600		2,004,287	52,500	58,500		1,469,925		1,104,615

1. This table shows the number and value of exercisable and unexercisable stock options for the named executive officers during 2005. The value is determined using the closing market price of Exelon common stock on December 31, 2005, which was $54.35, less the exercise price of the options. All options whose exercise price exceeded the market price at the day of determination are valued at zero. For all data above, the number of shares and exercise prices have been adjusted to reflect the 2 for 1 stock split of May 5, 2004.

2. The value shown in this column is the gross proceeds from the exercise and sale which is the number of shares sold multiplied by the spread between sale price of the shares and the option strike price. This figure does not reflect any taxes or brokerage fees. All options exercised by Messrs. Skolds, Rowe and Mitchell during 2005 were done in accordance with a Rule 10b5-1 Trading Plans, which were entered into at such time when the officer was unaware of any material adverse information in regard to current and prospective operations of Exelon which had not been publicly disclosed. The dates of the sales were set at the time the Trading Plan was established. Of the total shares exercised during 2005 by Mr. Rowe, he retained 93,201.

451

Long-Term Incentive Plans—Awards in Last Fiscal Year

	Number of Shares, Units or Other Rights (See Note 1)	Performance Period until Maturation or Payout.	Estimated future payouts under non-stock price-based plans (See Note 2)
			Threshold	Target	Maximum
	(#)		(#)	(#)	(#)
John L. Skolds	N/A	3 years	8,500	17,000	34,000
John F. Young	N/A	3 years	8,500	17,000	34,000
John W. Rowe	N/A	3 years	34,500	69,000	138,000
Christopher M. Crane	N/A	3 years	6,000	12,000	24,000
Ian P. McLean	N/A	3 years	8,500	17,000	34,000
Mark A. Schiavoni	N/A	3 years	2,000	4,000	8,000
J. Barry Mitchell	N/A	3 years	3,500	7,000	14,000

1. Exelon’s Long Term Performance Share Award program under the Long-Term Incentive Plan provides incentives to key executives in the form of restricted stock and cash. Awards are determined upon the successful completion of strategic goals designed to achieve long term business success and increased shareholder value. These goals include Exelon’s Total Shareholder Return (TSR) over the previous three years relative to established benchmarks including a peer group of companies listed on the Dow Jones Utility Index (weighted 50%) and the Standard & Poor’s 500 Index (weighted 20%) and a quantifiable cash savings goal aligned with The Exelon Way initiative (weighted 30%). Grants under the Long Term Performance Share Award Program for 2005 are reflected in the Summary Compensation Table. See note 2 to that table.

2. A target number of performance shares is established for each participant which is commensurate with the participant’s base salary. Based on measured performance as described above, participants may earn up to 200% of their target and may earn nothing if thresholds are not met.

Retirement Benefit Plans

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. The amounts shown in the table are not subject to any reductions for social security or other offset amounts.

Exelon sponsors the Exelon Corporation Retirement Program, a traditional defined benefit pension plan that covers certain management employees who commenced employment prior to January 1, 2001 and certain collective bargaining unit employees. Effective January 1, 2001, Exelon also established two cash balance defined benefit pension plans which cover management employees and certain collective bargaining unit employees hired on or after such date, as well as certain management employees hired prior to such date who elected to transfer to a cash balance plan. Each of these plans is intended to be tax-qualified under Section 401(a) of the Internal Revenue Code.

Covered compensation under the plans generally includes salary and bonus which is disclosed in the Summary Compensation Table under “—Executive Compensation” for the named executive officers. The calculation of retirement benefits under the Exelon Corporation Retirement Program 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 individual annual compensation that may be taken into account under tax-qualified retirement plan to $210,000 as of January 1, 2005 and the amount that an individual may accrue in one year under such a defined benefit plan to $170,000 as of January 1, 2005. As permitted by the Employee Retirement Income Security Act of 1974, as amended, Exelon sponsors supplemental pension plans which allow the payment to certain individuals out of its general assets of any benefits calculated under provisions of the applicable qualified pension plan which may be above these limits.

452

Service Annuity System Benefit Table—PECO

(applicable to employees of Exelon, PECO and Generation)

	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	$	18,878	$	25,817	$	32,756	$	39,695	$	46,634	$	53,573	$	60,512
200,000		39,378		54,067		68,756		83,445		98,134		112,823		127,512
300,000		59,878		82,317		104,756		127,195		149,634		172,073		194,512
400,000		80,378		110,567		140,756		170,945		201,134		231,323		261,512
500,000		100,878		138,817		176,756		214,695		252,634		290,573		328,512
600,000		121,378		167,067		212,756		258,445		304,134		349,823		395,512
700,000		141,878		195,317		248,756		302,195		355,634		409,073		462,512
800,000		162,378		223,567		284,756		345,945		407,134		468,323		529,512
900,000		182,878		251,817		320,756		389,695		458,634		527,573		596,512
1,000,000		203,378		280,067		356,756		433,445		510,134		586,823		663,512

Service Annuity System Benefit Table—ComEd

(applicable to employees of Exelon, ComEd and Generation)

	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	$	16,044	$	27,927	$	38,917	$	49,202	$	58,949	$	68,290	$	77,323
200,000		32,088		56,553		79,180		100,352		120,395		139,562		158,053
300,000		48,132		85,178		119,442		151,502		181,839		210,833		238,782
400,000		64,176		113,804		159,705		202,652		243,284		282,105		319,511
500,000		80,220		142,429		199,968		253,802		304,729		353,377		400,240
600,000		96,264		171,055		240,231		304,952		366,173		424,648		480,969
700,000		112,308		199,681		280,494		356,102		427,618		495,920		561,698
800,000		128,352		228,306		320,757		407,253		489,062		567,191		642,427
900,000		144,395		256,931		361,020		458,403		550,508		638,462		723,157
1,000,000		160,439		285,557		401,283		509,553		611,952		709,735		803,886

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, 2005 (partial years are not included):

Exelon	(a)	PECO	(a)
John W. Rowe	27 years	John L. Skolds	13 years
John L. Skolds	13 years	John W. Rowe	27 years
Randall E. Mehrberg	15 years	John F. Young	2 years
John F. Young	2 years	Denis P. O’Brien	23 years
Frank M. Clark	40 years	Matthew F. Hilzinger	3 years
		J. Barry Mitchell	34 years

ComEd	(a)	Generation	(a)
John L. Skolds	13 years	John L. Skolds	13 years
Frank M. Clark	40 years	John F. Young	2 years
J. Barry Mitchell	34 years	John W. Rowe	27 years
Robert K. McDonald	27 years	Christopher M. Crane	14 years
John T. Costello	35 years	Ian P. McLean	6 years
John T. Hooker	38 years	Mark A Schiavoni	5 years
John W. Rowe	27 years	J. Barry Mitchell	34 years
Ruth Ann M. Gillis	8 years

(a) Actual and credited years of service.

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Credited Years of Service: Mr. Skolds received an additional 7 ¹/2 years of service upon his 5th anniversary of employment and will receive an additional 7 ¹/2 years upon his 10th anniversary; Mr. Mehrberg received an additional 10 years upon his 5^th anniversary; and Mr. Crane receives an additional year for each year until his 10^th anniversary. As of January 1, 2004, Exelon does not grant additional years of credited service to executives under the non-qualified pension plans that supplement the Exelon Corporation Retirement Program for any period in which services are not actually performed, except that up to two years of service credits may be provided under severance or change in control agreements first entered into after such date. Service credits previously available under employment, change in control or severance agreements or arrangements (or any successors agreements or arrangements) are not affected by this policy.

Cash Balance Pension Plan:Mr. Hilzinger, Mr. McLean, Mr. O’Brien and Mr. Young participate in the Exelon Corporation Cash Balance Pension Plan. Under this 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 annual incentive award (subject to applicable Internal Revenue Code limit). The annual investment credit is the greater of 4% or the average for the year of the S&P 500 Index and the applicable interest rate used under Section 417(e) of the Internal Revenue Code to determine lump sums, determined as of November of such year. Benefits are vested and nonforfeitable after completion of at least five years of service, and are payable following termination of employment. Apart from the benefit credits and vesting requirement, and as described above, years of service are not relevant to a determination of accrued benefits under the Cash Balance Pension Plan. As of January 1, 2004, Exelon does not grant additional years of credited service to executives under the non-qualified pension plan that supplements the Exelon Corporation Cash Balance Pension Plan for any period in which services are not actually performed, except that (1) service credits may be granted to a newly-hired executive to make the executive whole for the loss of pension benefits from the executive’s prior employer, (2) performance-based service credits may be granted under the supplemental plan and (3) up to two years of service credits may be granted under severance or change in control agreements first entered into after such date. Exelon will publicly disclose the methods used to determine any grants described under clauses (1) or (2) of the preceding sentence. Service credits previously available under employment, change in control or severance agreements or arrangements (or any successor agreements of arrangements) are not affected by this policy.

Employment Agreements

Employment Agreement with Mr. Rowe

Under the amended and restated employment agreement between Exelon and Mr. Rowe, Mr. Rowe will continue to serve as Chief Executive Officer of Exelon, Chairman of Exelon’s Board of Directors and a member of the Board of Directors until March 16, 2010, except that E. James Ferland (current Chief Executive Officer of PSEG) will be appointed non-executive Chairman of Exelon’s Board of Directors upon the closing of the merger between Exelon and PSEG, and Mr. Rowe will be reappointed as Chairman as of April 1, 2007 or such earlier date that Mr. Ferland ceases to serve as Chairman.

Under the employment agreement, which continues in effect until Mr. Rowe’s termination, his annual base salary is determined by Exelon’s compensation committee. Mr. Rowe 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.

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In addition, Mr. Rowe is entitled to receive a special supplemental executive retirement plan, the “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 of that date occurring prior to his termination of employment; and

• 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.

In the event Mr. Rowe’s employment terminates for cause on or before March 16, 2006 (the “normal retirement date” specified in his prior employment agreement), the SERP benefit is forfeited. If his employment terminates for cause after March 16, 2006, the forfeiture is limited to the portion of the SERP benefit that accrues after March 16, 2006. Upon any termination for cause, all stock options (whether vested or non-vested) and non-vested performance shares and restricted stock also would be forfeited.

If, prior to March 16, 2010, Exelon terminates Mr. Rowe’s employment for reasons other than cause, death or disability or Mr. Rowe terminates his employment for good reason, he would also be eligible for the following benefits:

• a lump sum payment of Mr. Rowe’s accrued but unpaid base salary and annual incentive, if any, and a prorated formula annual incentive (determined in accordance with the following subparagraph) for the year in which his employment terminates;

• for the lesser of two years or the period remaining until March 16, 2010, continued periodic payment of base salary and continued periodic payment of a formula annual incentive equal to either the annual incentive for the last year ending prior to termination or the average of the annual incentives payable with respect to Mr. Rowe’s last three full years of employment, whichever is greater;

• during the severance period, continuation of life, disability, accident, health and other active welfare benefits for him and his family, followed by post-retirement health care coverage for him and his wife for the remainder of their respective lives;

• all exercisable stock options remain exercisable until the applicable option expiration date, except that options granted on or after January 1, 2002 remain exercisable for five years, consistent with the terms of Exelon’s long term incentive plan (LTIP);

• non-vested stock options become exercisable and thereafter remain exercisable until the applicable option expiration date, except that options granted on or after January 1, 2002 remain exercisable for five years, consistent with the terms of the LTIP;

• previously earned but non-vested performance shares vest and a target award for the year in which the termination occurs, consistent with the terms of the performance share award program under the LTIP; and

• any non-vested restricted stock award vests.

Mr. Rowe would receive the termination benefits described in the preceding paragraph, if, prior to March 16, 2010, Exelon terminates Mr. Rowe without cause or he terminates his employment for 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 such terms are described under “Change in Control

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Employment Agreements and Severance Plan Covering Other Named Executives,” except that the pending merger of Exelon and PSEG is specifically excluded from such terms; or

• Mr. Rowe resigns before March 16, 2010 because of the failure to be appointed or elected as Exelon’s Chief Executive Officer, Chairman of Exelon’s Board of Directors (other than during Mr. Ferland’s term as Chairman), and a member of the Board of Directors;

except that:

• the formula annual incentive award payable for the year in which Mr. Rowe’s employment terminates will be paid in full, rather than prorated;

• in lieu of continued periodic payment of base salary and formula annual incentive, he will receive a lump sum severance payment equal to his base salary and the formula annual incentive multiplied by the lesser (i) three and (ii) the number of years (including fractional years) remaining until March 16, 2010;

• in determining the amount of such full formula annual incentive and lump sum severance payment, the formula annual incentive will be the greater of the amount described in the preceding paragraph or the target annual incentive for the year in which his employment terminates;

• continued active welfare benefits will be provided for the lesser of three years and the period remaining until March 16, 2010;

• the SERP benefit will be determined taking into account the lump sum severance payments, as though it were paid in installments and Mr. Rowe remained employed during the severance period; and

• professional outplacement services will be provided for up to twelve months.

The term “good reason” means any material breach of the employment agreement by Exelon, including:

• a failure to provide compensation and benefits required under the employment agreement (including a reduction in base salary that is not commensurate with and applied to Exelon’s other senior executives) without Mr. Rowe’s consent;

• causing Mr. Rowe to report to someone other than Exelon’s Board of Directors;

• any material adverse change in Mr. Rowe’s status, responsibilities or perquisites; or

• any announcement by Exelon’s Board of Directors without Mr. Rowe’s consent that Exelon is seeking his replacement, other than with respect to the period following his retirement.

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:

• 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;

• the failure of any successor to assume his employment agreement;

• a relocation of Exelon’s office by more than 50 miles; or

• a 20% increase in the amount of time that Mr. Rowe must spend traveling for business outside of the Chicago area.

The term “cause” means any of the following, unless cured within the time period specified in the agreement:

• conviction of a felony or of a misdemeanor involving moral turpitude, fraud or dishonesty;

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• willful misconduct in the performance of duties intended to personally benefit the executive; or

• material breach of the agreement (other than as a result of incapacity due to physical or mental illness).

Upon Mr. Rowe’s retirement or other termination of employment other than for cause:

• Mr. Rowe is required to provide up to ten hours per week of transition services for six months and, thereafter, until the third anniversary of his termination, at Exelon’s request, to provide consulting services, attend a reasonable number of civic, charitable and corporate events, and serve on mutually agreed civic and charitable boards as Exelon’s representative;

• Exelon is required to provide office space, a personal secretary and reasonably requested tax, financial and estate planning services to Mr. Rowe for three years (or one year following his death);

• he will receive a prorated formula annual incentive for the year in which the termination occurs;

• all exercisable stock options remain exercisable until the applicable option expiration date, except that options granted on or after January 1, 2002 remain exercisable for five years, consistent with the terms of the LTIP;

• non-vested stock options become exercisable and thereafter remain exercisable until the applicable option expiration date, except that options granted on or after January 1, 2002 remain exercisable for five years, consistent with the terms of the LTIP;

• previously earned but non-vested performance shares vest and he will receive a target award for the year in which the termination occurs, consistent with the terms of the performance share award program under the LTIP; and

• if the termination occurs on or after March 16, 2006, any non-vested restricted stock award vests, unless otherwise provided in the grant instrument.

The term “retirement” means:

• Mr. Rowe’s termination of his employment other than for good reason, disability or death;

• Exelon’s termination of his employment on or after March 16, 2010 other than for cause or disability.

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. He is also 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 any payment to Mr. Rowe would be subject to a penalty under section 409A of the Internal Revenue Code, Exelon may postpone such payment by up to six months to avoid such penalty or the parties may amend the agreement to comply with section 409A.

Change in Control Employment Agreements and Severance Plan Covering Other Named Executives

Exelon has entered into change in control employment agreements with the named executive officers other than Mr. Rowe, which generally protect such executives’ position and compensation levels for two years after a change in control of Exelon. The agreements are initially effective for a period of two years, and provide for a one-year extension each year thereafter until cancellation or termination of employment.

During the 24-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

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shareholders retain between 60% and 66 ²/3% control (a “significant acquisition”), if a named executive officer resigns for good reason or if the executive’s employment is terminated by Exelon 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 supplemental executive retirement plan (“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 who entered into such agreements 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 any non-vested accrued benefit under Exelon’s qualified defined benefit retirement plan;

• all stock 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, followed by retiree health coverage if the executive has attained at least age 50 and completed at least ten years of service (or any lesser eligibility requirement then in effect for regular employees); and

• outplacement services for at least twelve months.

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 which, if consummated, 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:

• when any person acquires 20% of Exelon’s voting securities;

• when the incumbent members of the Exelon 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 Exelon board of directors;

• 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 shareholders retain at least 60% of the voting power); or

• upon shareholder approval of a plan of complete liquidation or dissolution.

The term “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:

• a material reduction in salary, incentive compensation opportunity or aggregate benefits, unless such reduction is part of a policy, program or arrangement applicable to peer executives;

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• failure of a successor to assume the agreement;

• a material breach of the agreement by Exelon; or

• any of the following, but only after a change in control or disaggregation: (1) a material adverse reduction in the executive’s position, duties or responsibilities (other than a change in the position or level of officer to whom the executive reports or a change that is part of a policy, program or arrangement applicable to peer executives) or (2) a required relocation by more than 50 miles.

The term “cause” under the change in control employment agreements generally includes any of the following:

• refusal to perform or habitual neglect in the performance of duties or responsibilities or of specific directives of the officer to whom the executive reports which are not materially inconsistent with the scope and nature of the executive’s duties and responsibilities;

• willful or reckless commission of acts or omissions which have resulted in or are likely to result in a material loss or material damage to the reputation of Exelon or any of its affiliates, or that compromise the safety of any employee;

• commission of a felony or any crime involving dishonesty or moral turpitude;

• material violation of the code of business conduct which would constitute grounds for immediate termination of employment, or of any statutory or common-law duty of loyalty; or

• any breach of the executive’s restrictive covenants.

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.

If a named executive officer other than Mr. Rowe resigns for good reason or is terminated by Exelon other than for cause or disability, in each case under circumstances not covered by an individual change in control employment agreement, the named executive officer may be eligible for the following non-change in control benefits under the Exelon Corporation Senior Management Severance Plan:

• prorated payment of the executive’s target annual incentive for the year in which termination occurs;

• for a two-year severance period, continued payment of base salary and continued payment of annual incentive equal to the executive’s target incentive for the year in which the termination occurs;

• a benefit equal to the amount payable under the SERP determined as if the severance payments were paid as ordinary base salary and annual incentive;

• for the two-year severance period, continuation of health, basic life and other welfare benefits the executive was receiving immediately prior to the severance period, followed by retiree health coverage if the executive has attained at least age fifty and completed at least ten years of service (or any lesser eligibility requirement then in effect for non-executive employees); and

• outplacement services for at least six months.

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Payments under the Senior Management Severance Plan are subject to reduction by Exelon to the extent necessary to avoid imposition of excise taxes imposed by Section 4999 of the Internal Revenue Code on “excess parachute payments” or under similar state or local law.

Consummation of the pending merger with PSEG is not a change in control and is not expected to be a significant acquisition under the change in control employment agreements or the Senior Management Severance Plan. Subject to the consummation of the merger and pursuant to the authorization previously disclosed in Exelon’s 2005 Joint Proxy Statement and Prospectus, non-change in control benefits payable under the plan to an executive who has completed at least two years of service and who is terminated without cause or resigns for good reason between September 1, 2005 and the second anniversary of the merger consummation will be adjusted in the following respects: (1) the participant will receive a target annual incentive and target performance share award, rather than a prorated target annual incentive and performance share award, for the year in which termination occurs, (2) in determining the amount of continued annual incentive during the severance period, the payment would be based on the higher of the executive’s target annual incentive in the year of termination or the executive’s average annual incentives for the two years preceding termination, 3) non-vested stock options and restricted stock (unless the terms of the restricted stock grant provide that vesting will not accelerate) of an eligible executive who terminates employment on or after February 13, 2006 will vest and all stock options will remain exercisable for the period permitted under section 409A of the Internal Revenue Code, and 4) an executive who declines a relocation that would increase the executive’s one-way commuting distance by more than 50 miles may resign and receive severance benefits consistent with those provided to key management employees under Exelon’s non-executive severance plan.

The term “good reason” under the Senior Management Severance Plan means either of the following:

• a material reduction of the executive’s salary, incentive compensation opportunity or aggregate benefits unless such reduction is part of a policy, program or arrangement applicable to peer executives of Exelon or of the business unit that employs the executive; or

• a material adverse reduction in the executive’s position or duties (other than a change in the position or level of officer to whom the executive reports) that is not applicable to peer executives of Exelon or of the executive’s business unit, but excluding any change (1) resulting from a reorganization or realignment of all or a significant portion of the business, operations or senior management of Exelon or of the executive’s business unit or (2) that generally places the executive in substantially the same level of responsibility.

The term “cause” under the Senior Management Severance Plan has the same meaning as the definition of such term under the individual change in control employment agreements.

Report of the Exelon Compensation Committee

Committee Responsibilities and Procedures. The Exelon compensation committee (the “Committee”) reviews and oversees executive compensation and other benefit and compensation programs. The Committee makes recommendations to the independent directors for approval of compensation for the Chairman and CEO and to the full board of directors for executive vice presidents. A copy of the Committee’s charter is posted on Exelon’s website,www.exeloncorp.com, on the Investor Relations page under “Corporate Governance.” All members of the Committee are independent directors. When appropriate, the Committee uses the services of a compensation consultant who reports directly to the Committee.

Each year the Committee’s compensation consultant advises the Committee on best practices in executive compensation and assesses Exelon’s compensation practices and pay levels. In 2005, the

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Committee reviewed tally sheets for senior executives that reflected the total value of payments and benefits that would be received upon termination of employment due to retirement or voluntary termination, involuntary separation not related to a change in control, and qualifying termination following a change in control. The Committee annually reviews the perquisites made available to the company’s senior executives. The Committee also oversees the company’s executive stock ownership requirements.

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. The program is benchmarked with the best practices of energy services companies and large, asset-intensive general industry companies. This philosophy reflects a commitment to attracting and retaining key executives to ensure continued focus on achieving long-term growth in shareholder value.

Exelon’s executive compensation program is comprised of three elements:

• base salary;

• annual incentives; and

• long-term incentives.

These components balance short-term and longer range business objectives and align executives’ financial rewards with shareholders’ interests.

The Committee has adopted a pay-for-performance philosophy, which 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. For Mr. Rowe, 85% of his 2005 target total direct compensation (base salary plus annual and long-term incentive award opportunity) was at-risk. Similarly, 75% of the other named executive officers’ 2005 target total direct compensation was at-risk.

Executive Stock Ownership Requirements. To strengthen the alignment of executives’ interests with those of shareholders, officers of the company are required to own certain amounts of Exelon common stock, by the later of five years after their employment or January 1, 2006. Ownership is measured using a market value equal to or greater than the following multiples of their base salary: 1) Chairman and Chief Executive Officer, five times base salary; 2) President and executive vice presidents, three times base salary; and 3) senior vice presidents, two times base salary; and 4) vice presidents and other officers, one times base salary. The Committee adopted a policy requiring officers, executive vice presidents and above, who wish to sell Exelon common stock to do so only through Section 10b5-1 stock trading plans, and permitting other officers to enter into such plans. This requirement is designed to enable officers to diversify a portion of their holdings in excess of the applicable stock ownership requirements in an orderly manner as part of their estate and tax planning activities.

Factors Considered in Determining Overall Compensation. The Committee commissioned a study of compensation programs in the fall of 2004. This analysis was conducted by a leading global compensation consulting firm and included an assessment of business plans, strategic goals, and competitive compensation levels at high-performing energy services companies and other large, asset-intensive companies in general industry. Generally, executive total direct compensation is targeted to approximate the median (50th percentile) levels of the companies identified and surveyed. The Committee also takes into consideration unique circumstances required to attract and retain talent. The study results indicated that Exelon’s mix of compensation components (i.e., base salary, annual and long-term incentives) is effectively aligned with the best practices of these companies.

Chief Executive Officer Compensation. The Chief Executive Officer participates in the same programs and receives compensation based on the same factors as the other named executive officers.

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However, Mr. Rowe’s overall compensation reflects a greater degree of policy and decision-making authority and a higher level of responsibility with respect to the strategic direction and financial and operating results of the company. As such, the independent directors of the Exelon board, on the recommendations of the Exelon corporate governance committee, conducted a thorough review of Mr. Rowe’s performance in 2004 and 2005. The review considered performance requirements in the areas of finance and operations, strategic planning and implementation, succession planning and organizational goals, communications and external relations, board relations, leadership, and shareholder relations. Mr. Rowe prepared a detailed self-assessment reporting to the board on his performance during the year with respect to each of the performance requirements. The board considered the financial highlights of the year and a strategy scorecard that assessed performance against the company’s commitments with respect to operational reliability, safety, environmental performance, employee relations, diversity, and disclosure. The board also considered performance with respect to goals relating to operational performance, the development of a common business model, optimizing the relationships among Exelon’s business units, promoting effective markets, and adapting to changing markets and politics. Other goals the board assessed included maximizing earnings and cash from assets and business and progress toward accomplishing the proposed merger with PSEG. The board considered in particular strong results in the growth in operating earnings, the high nuclear capacity factor, improvements made to the delivery system and the size of the company’s market capitalization. It also considered areas where results were less than hoped for, such as delays in obtaining merger approvals and the regulatory difficulties for ComEd in Illinois, the need to continue improving delivery service, and the need to make further improvements in information technology and controls.

How Base Salary is Determined. Base salaries for Exelon’s executives are determined based on individual performance and experience, with reference to the salaries of executives in similar positions in the peer group.

Mr. Rowe’s 2005 Base Salary. The independent directors of the Exelon board, on the recommendations of the Committee and the Exelon corporate governance committee, 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 the Committee’s consultant;

• performance achieved against financial and operational goals; and

• the performance review discussed above.

Mr. Rowe’s annualized base salary was considered to be competitive and remained at $1,250,000 during 2005.

Other Named Executives’ 2005 Base Salaries. The base salaries of the other named executive officers listed in the Summary Compensation Table were determined based upon the recommendations of the Committee by considering comparable compensation data from the study referred to above and performance achieved against financial, operational and individual goals. Messrs. Skolds, Clark, Young and Mehrberg received base salary increases during 2005 to recognize an expansion of each of the executive’s responsibilities.

How 2005 Annual Incentives are Determined. Annual incentives for Exelon’s executives are determined based on the achievement of corporate and business unit measures that the Committee establishes at the beginning of each year. These measures are based on factors necessary to achieve strategic business objectives. These measures may include financial, operational, customer and internal indicators designed to measure corporate and business unit performance. Each participant in the annual incentive plan is assigned a target percentage of base salary at the beginning of each year based on the benchmarking data referred to above. These target percentages increase with responsibility and may be adjusted to reflect promotions during the year.

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For 2005, the annual incentive payments to Mr. Rowe and each of nine other senior executives were funded by an incentive pool established by the Exelon board of directors under the Annual Incentive Plan for Senior Executives, a shareholder-approved plan, which is intended to comply with Section 162(m) of the Internal Revenue Code. The incentive pool was funded with 1.5% of Exelon’s operating income, but was not fully distributed to participants because the Committee decided on lesser awards.

Annual incentive payments for 2005 to named executives were based on the achievement of a pre-determined corporate measure (operating earnings per share, adjusted for non-operating charges and other one-time, unusual and non-recurring items), customer satisfaction, diversity goals and individual performance. The incentive plan was designed to directly link annual incentives to the achievement of key goals of Exelon and, as applicable, the executive’s individual performance.

Mr. Rowe’s 2005 Annual Incentive. Taking into account the performance review discussed above, the Committee recommended and the board of directors approved an award of $1,642,266 for Mr. Rowe, which is 131.38% of his target annual incentive opportunity.

Other Named Executive Officers’ 2005 Annual Incentives. The Committee recommended and the board of directors approved awards for other named executives that represented 119.44% of each executive’s target opportunity.

Long-Term Incentives. Exelon awards a combination of non-qualified stock options and performance shares to focus executives on long-term value creation and the achievement of key performance goals. Half (50%) of the long-term incentive is delivered as stock options and half (50%) is delivered as performance shares.

Stock Option Awards. Exelon granted stock options to key management employees, including the named executive officers, on January 24, 2005. The purpose of stock options is to tie long-term incentive compensation directly to increases in stock price. 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 vest in equal annual installments over a four-year period and have a term of ten years.

Mr. Rowe and other named executive officers were awarded a number of non-qualified stock options equal to their target awards on January 24, 2005. Mr. Rowe was awarded a grant of 229,000 non-qualified stock options on this date with an exercise price of $42.85 per share.

Exelon Performance Share Awards. Exelon grants performance shares in order to link executives’ long-term incentive compensation to the achievement of pre-established performance measures and shareholder value. Awards are denominated in shares of Exelon common stock. Payouts earned under the Long-Term Performance Share Program are generally paid in shares of Exelon common stock. One-third of the shares vest upon the award date, one-third vest on the first anniversary of the award date, and the final one-third of the shares vest on the second anniversary of the award date in order to foster retention. Executives receive earned awards in a combination of Exelon common stock and cash if they have achieved 125% of their stock ownership requirement. Beginning in 2005, executive vice presidents and the CEO receive earned awards entirely in cash if they have achieved 200% of their stock ownership requirement.

Payouts for the 2005 Long-Term Performance Share Program were based on three measures, (1) Exelon’s three-year Total Shareholder Return, compounded monthly, (“TSR”), as compared to the TSR for the companies listed in the Dow Jones Utility Index, (2) Exelon’s three-year TSR, as compared to the companies in the Standard and Poor’s 500 Index, and (3) cash savings during 2005 from The Exelon Way initiative. For 2005, 70% of the award was tied to Exelon’s TSR components, with the balance tied to achievement of the cash savings goal during 2005 from The Exelon Way initiative.

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Exelon exceeded target performance levels with respect to both TSR measures, but did not fully achieve the target performance level for cash savings during 2005 from The Exelon Way initiative. Overall performance against the three measures resulted in a payout to participants for 2005 that represented 122.5% of each participant’s target opportunity.

Based on these results, the board of directors approved Mr. Rowe’s 2005 Performance Share Award of 84,525 shares of Exelon common stock, which had a value of $4,948,939 on the grant date (based on the closing stock price of $58.55 on January 23, 2006). Mr. Rowe exceeded 200% of his stock ownership requirement (five times his annualized base salary) and received his entire award in cash. Messrs. Skolds and Clark exceeded 200% of their stock ownership requirement (three times annualized base salary) and received their awards in cash. Mr. Mehrberg exceeded 125%, but was below 200% of his stock ownership requirement (three times his annualized base salary) and, therefore, received his award in a combination of cash and Exelon common stock. Mr. Young received his entire award in Exelon common stock because he was below 125% of his stock ownership requirement (three times his annualized base salary).

Executive Perquisites. Exelon provides perquisites designed to attract and retain executive officers to the company. Some perquisites are intended to serve a specific business need for the benefit of the company; however, it is understood that some may be used for personal reasons as well. When perquisites are utilized for purely personal reasons, the cost is imputed to the officer as income and the officer is responsible for all applicable taxes; however, in certain cases, the personal benefit is closely associated with the business purpose and the company reimburses the officer for the taxes due on the imputed income.

The executive perquisite program was benchmarked against large energy and general industry companies. The Committee reviewed the costs of the perquisite program and determined the costs to be appropriate for a company of Exelon’s size. The Summary Compensation Table and related footnotes summarize the cost of the perquisites.

Ability to Deduct Executive Compensation. Under Section 162(m) of the Internal Revenue Code, executive compensation in excess of $1 million paid to a chief executive officer or other person among the four other highest compensated officers is generally not deductible for purposes of corporate federal income taxes. However, “qualified performance-based compensation” within the meaning of Section 162(m) of the Internal Revenue 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.

For 2005, annual incentive payments and awards under the Performance Share Program to the named executive officers qualify as performance-based compensation under Section 162(m) of the Internal Revenue Code.

February 14, 2006

Exelon Compensation Committee

Edward A. Brennan, Chair

M. Walter D’Alessio

Rosemarie B. Greco

Ronald Rubin

Richard L. Thomas

464

Stock Performance Graph

The performance graph below illustrates a five year comparison of cumulative total returns based on an initial investment of $100 in Exelon Corporation common stock, as compared with the S&P 500 Stock Index and the S&P Utility Average for the period 2000 through 2005.

This performance chart assumes:

• $100 invested on December 31, 2000 in Exelon Corporation common stock, in the S&P 500 Stock Index and in the S&P Utility Index; and

• All dividends are reinvested.

	2000		2001		2002		2003		2004		2005
Exelon Corporation	$	100.00	$	70.50	$	80.40	$	104.40	$	143.39	$	178.41
S&P 500		100.00		88.17		68.73		88.41		97.99		102.80
S&P Utilities		100.00		69.68		48.81		61.51		76.35		89.11

465

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Exelon

The following table shows the ownership of Exelon common stock as of January 31, 2006 by any person or entity that has publicly disclosed ownership of more than five percent of Exelon’s outstanding stock, each director, each executive officer named in the Summary Compensation Table, and for all directors and executive officers as a group.

Beneficial Ownership Table

	[A] Beneficially Owned Shares (See Note 1)	[B] Shares Held in Company Plans (See Note 2)	[C] = [A] + [B] Total Shares Held	[D] Share Equivalents to be Settled in Cash or Stock (See Note 3)	[E] = [C] + [D] Total Share Interest
5% Holders (see Note 4)
Capital Research and Management Company	46,583,900		46,583,900		46,583,900
Wellington Management Company, LLP	41,276,740		41,276,740		41,276,740
Directors
Edward A. Brennan	8,252	12,854	21,106	11,578	32,684
M. Walter D’Alessio	10,935	31,871	42,806	—	42,806
Nicholas DeBenedictis	1,000	6,078	7,078	—	7,078
Bruce DeMars	9,436	10,265	19,701	—	19,701
Nelson A. Diaz	1,000	2,519	3,519	781	4,300
Sue L. Gin	26,715	11,810	38,525	6,755	45,280
Rosemarie B. Greco	2,000	14,605	16,605	4,778	21,383
Edgar D. Jannotta	13,240	21,646	34,886	9,065	43,951
John M. Palms	2,686	26,416	29,102	—	29,102
William C Richardson	—	972	972	—	972
Thomas J. Ridge	—	752	752	—	752
John W. Rogers, Jr.	11,374	12,259	23,633	6,422	30,055
Ronald Rubin	15,129	31,755	46,884	825	47,709
Richard L. Thomas	21,930	17,548	39,478	9,383	48,861
Named Officers
John W. Rowe	1,834,865	273,003	2,107,868	128,720	2,236,588
John L. Skolds	160,244	73,879	234,123	31,240	265,363
Randall E. Mehrberg	84,400	75,859	160,259	14,281	174,540
John F. Young	66,787	27,282	94,069	746	94,815
Frank M. Clark	149,171	35,359	184,530	27,753	212,283
Total
Directors & Executive Officers as a group, 23 people. (See Note 5)	3,067,707	805,721	3,873,428	325,400	4,198,828

1. The shares listed above under Beneficially Owned Shares, Column [A], include shares that may be acquired from non-qualified stock options that are fully vested or that vest within 60 days of January 31, 2006.

2. The shares listed above under Shares Held in Company Plans, Column [B], include restricted shares, shares held in the 401(k) plan, and unvested performance shares that are expected to be settled in shares depending on where the named officer stands with respect to their stock ownership requirement.

3. The shares listed above under Share Equivalents to be Settled in Cash, Column [D], include the unvested portion of performance shares that are expected to be settled in cash depending on where the named officer stands with respect to their stock ownership requirement, and phantom shares held in a non-qualified deferred compensation plan which will be settled in cash on a 1 for 1 basis upon retirement or termination.

4. In a Schedule 13G filed with the SEC on February 10, 2006, an investment adviser, Capital Research and Management Company, 333 South Hope Street, Los Angeles, CA 90071, disclosed that as of December 31, 2005, it is deemed to be the beneficial owner of 46,583,900 shares, or approximately 7.0% of Exelon’s issued and outstanding shares, although it disclaimed beneficial ownership pursuant to Rule 13d-4. Capital Research disclosed that it had sole dispositive power of 46,583,900 shares.

In a Schedule 13G filed with the SEC on February 14, 2006, an investment adviser, Wellington Management Company, LLP, 75 State Street, Boston, MA 02109, disclosed that as of December 31, 2005, it was the beneficial owner of 41,276,740 shares or approximately 6.19% of Exelon’s issued and outstanding shares. Wellington disclosed that it shared power to vote 23,896,229 shares and shared power to dispose of 41,276,740 shares.

5. Beneficial ownership, shown in Column [A], of directors and executive officers as a group represents less than 1% of the outstanding shares of Exelon common stock.

466

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
Equity compensation plans approved by security holders	21,380,666	(a)	$	31.49	27,909,780	(b)
Equity compensation plans not approved by security holders	507,137	(c)		20.56	—
Total	21,887,803		$	31.23	27,909,780

(a) Includes 213,533 of deferred stock units earned by non-employee directors under approved plans.

(b) Excludes securities to be issued upon exercise of outstanding options. Includes 24 million shares approved in 2005 under the Long Term Incentive Plan effective January 1, 2006.

(c) Amount shown represents options issued under a broad based incentive plan available to all employees of PECO Energy Company. Options were issued beginning in November 1998 and no further grants were made after October 20, 2000.

ComEd

Exelon indirectly owns 127,002,904 shares of ComEd common stock, more than 99% of all outstanding shares. 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 ComEd voting securities.

The following table shows the ownership of Exelon common stock as of January 31, 2006 by (1) any director of ComEd, (2) each executive officer of ComEd named in the Summary Compensation Table, and (3) all directors and executive officers of ComEd as a group.

Beneficial Ownership Table

	[A] Beneficially Owned Shares (See Note 1)	[B] Shares Held in Company Plans (See Note 2)	[C] = [A] + [B] Total Shares Held	[D] Share Equivalents to be Settled in Cash or Stock (See Note 3)	[E] = [C] + [D] Total Share Interest
Directors
Sue L. Gin	26,715	11,810	38,525	6,755	45,280
Edgar D. Jannotta	13,240	21,646	34,886	9,065	43,951
John W. Rogers, Jr.	11,374	12,259	23,633	6,422	30,055
Richard L. Thomas	21,930	17,548	39,478	9,383	48,861
Named Officers
John L. Skolds	160,244	73,879	234,123	31,240	265,363
Frank M. Clark	149,171	35,359	184,530	27,753	212,283
J. Barry Mitchell	71,207	49,597	120,804	10,441	131,245
Robert K. McDonald	12,808	26,542	39,350	3,150	42,500
John T. Costello	25,036	12,971	38,007	3,798	41,805
John T. Hooker	11,848	12,728	24,576	4,193	28,769
John W. Rowe	1,834,865	273,003	2,107,868	128,720	2,236,588
Ruth Ann M. Gillis	191,300	47,420	238,720	20,545	259,265
Total
Directors & Executive Officers as a group, 13 people. (See Note 4)	2,553,620	605,678	3,159,298	261,465	3,420,763

1. The shares listed above under Beneficially Owned Shares, Column [A], include shares that may be acquired from non-qualified stock options that are fully vested or that vest within 60 days of January 31, 2006.

2. The shares listed above under Shares Held in Company Plans, Column [B], include restricted shares, shares held in the 401(k) plan, and unvested performance shares that are expected to be settled in shares depending on where the named officer stands with respect to their stock ownership requirement.

467

3. The shares listed above under Share Equivalents to be Settled in Cash, Column [D], include the unvested portion of performance shares that are expected to be settled in cash depending on where the named officer stands with respect to their stock ownership requirement, and phantom shares held in a non-qualified deferred compensation plan which will be settled in cash on a 1 for 1 basis upon retirement or termination.

4. Beneficial ownership, shown in Column [A], of directors and executive officers as a group represents less than 1% of the outstanding shares of Exelon common stock .

No ComEd securities are authorized for issuance under equity compensation plans. For information about Exelon Securities authorized for issuance to ComEd employees under Exelon equity compensation plans, see above under “Exelon-Securities Authorized Under Equity Compensation Plans.”

PECO

The following table shows the ownership of Exelon common stock as of January 31, 2006 by each director, each executive officer named in the Summary Compensation Table, and for all directors and executive officers as a group.

Beneficial Ownership Table

	[A] Beneficially Owned Shares (See Note 1)	[B] Shares Held in Company Plans (See Note 2)	[C] = [A] + [B] Total Shares Held	[D] Share Equivalents to be Settled in Cash or Stock (See Note 3)	[E] = [C] + [D] Total Share Interest
Named Officers
John L. Skolds	160,244	73,879	234,123	31,240	265,363
John W. Rowe	1,834,865	273,003	2,107,868	128,720	2,236,588
John F. Young	66,787	27,282	94,069	746	94,815
Denis P. O’Brien	82,747	11,500	94,247	7,572	101,819
Matthew F. Hilzinger	41,002	23,265	64,267	3,683	67,950
J. Barry Mitchell	71,207	49,597	120,804	10,441	131,245
Directors, Named & Executive Officers as a group, 12 people. (See Note 4)	2,256,852	458,526	2,715,378	182,402	2,897,780

1. The shares listed above under Beneficially Owned Shares, Column [A], include shares that may be acquired from non-qualified stock options that are fully vested or that vest within 60 days of January 31, 2006.

2. The shares listed above under Shares Held in Company Plans, Column [B], include restricted shares, deferred shares, shares held in the 401(k) plan, and unvested performance shares that are expected to be settled in shares depending on where the named officer stands with respect to their stock ownership requirement.

3. The shares listed above under Share Equivalents to be Settled in Cash, Column [D], include the unvested portion of performance shares that are expected to be settled in cash depending on where the named officer stands with respect to their stock ownership requirement, and phantom shares held in a non-qualified deferred compensation plan which will be settled in cash on a 1 for 1 basis upon retirement or termination.

4. Beneficial ownership, shown in Column [A], of directors and executive officers as a group represents less than 1% of the outstanding shares of Exelon common stock.

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.”

468

Generation

The following table shows the ownership of Exelon common stock as of January 31, 2006 by each named executive officer named in the Summary Compensation Table, and for all executive officers as a group.

Beneficial Ownership Table

	[A] Beneficially Owned Shares (See Note 1) #	[B] Shares Held in Company Plans (See Note 2) #	[C] = [A] + [B] Total Shares Held #	[D] Share Equivalents to be Settled in Cash or Stock (See Note 3) #	[E] = [C] + [D] Total Share Interest #
Named Officers
John L. Skolds	160,244	73,879	234,123	31,240	265,363
John F. Young	66,787	27,282	94,069	746	94,815
John W. Rowe	1,834,865	273,003	2,107,868	128,720	2,236,588
Christopher M. Crane	16,946	58,218	75,164	11,497	86,661
Ian P. McLean	295,884	3,785	299,669	25,040	324,709
Mark A. Schiavoni	9,223	19,734	28,957	4,319	33,276
J. Barry Mitchell	71,207	49,597	120,804	10,441	131,245
Total
Directors & Executive Officers as a group, 8 people. (See Note 4)	2,457,331	515,418	2,972,749	212,003	3,184,752

1. The shares listed above under Beneficially Owned Shares, Column [A], include shares that may be acquired from non-qualified stock options that are fully vested or that vest within 60 days of January 31, 2006.

2. The shares listed above under Shares Held in Company Plans, Column [B], include restricted shares, shares held in the 401(k) plan, and unvested performance shares that are expected to be settled in shares depending on where the named officer stands with respect to their stock ownership requirement.

3. The shares listed above under Share Equivalents to be Settled in Cash, Column [D], include the unvested portion of performance shares that are expected to be settled in cash depending on where the named officer stands with respect to their stock ownership requirement, and phantom shares held in a non-qualified deferred compensation plan which will be settled in cash on a 1 for 1 basis upon retirement or termination.

4. Beneficial ownership, shown in Column [A], of directors and executive officers as a group represents less than 1% of the outstanding shares of Exelon common stock.

No Generation securities are authorized for issuance under equity compensation plans. For information about Exelon securities authorized for issuance to Generation employees under Exelon equity compensation plans, see above under “Exelon—Securities Authorized Under Equity Compensation Plans.”

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Exelon

Blank Rome LLP provided legal services to Exelon during 2005 and 2004. Mr. Diaz, a member of the Exelon board of directors, became a partner of Blank Rome LLP in March 2004.

ComEd, PECO and Generation

None.

469

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Exelon

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.

The following table presents fees for professional audit services rendered by PricewaterhouseCoopers LLP for the audit of Exelon’s annual financial statements for the years ended December 31, 2005 and 2004, and fees billed for other services rendered by PricewaterhouseCoopers LLP during those periods. Fees include amounts related to the year indicated, which may differ from amounts billed.

	Year Ended December 31,
(in thousands)	2005		2004
Audit fees	$	9,450	$	6,976
Audit related fees(a)		110		2,128
Tax fees(b)		294		594
All other fees(c)		40		45

(a) Audit related fees consist of assurance and related services that are reasonably related to the performance of the audit or review of Exelon’s financial statements. This category includes fees for accounting assistance and due diligence in connection with proposed acquisitions or sales, employee benefit plan audits, internal control reviews, and consultations concerning financial accounting and reporting standards.

(b) Tax fees consist of the aggregate fees billed for professional services rendered by PricewaterhouseCoopers LLP for tax compliance, tax advice, and tax planning. These services included tax compliance and preparation services, including the preparation of original and amended tax returns, claims for refunds, and tax payment planning, and tax advice and consulting services, including assistance and representation in connection with tax audits and appeals, tax advice related to proposed acquisitions or sales, employee benefit plans and requests for rulings or technical advice from taxing authorities.

(c) All other fees reflect work performed primarily in connection with corporate executive programs.

ComEd, PECO and Generation

ComEd, PECO and Generation are indirect controlled subsidiaries of Exelon and do not have separate audit committees. Instead, that function is fulfilled for these companies 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

470

$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 tables present fees for professional audit services rendered by PricewaterhouseCoopers LLP for the audit of ComEd’s, PECO’s and Generation’s annual financial statements for the years ended December 31, 2005 and 2004, 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. Fees include amounts related to the year indicated, which may differ from amounts billed.

ComEd

	Year Ended December 31,
(in thousands)	2005		2004
Audit fees	$	2,164	$	2,157
Audit related fees (a)		79		13
Tax fees (b)		43		24
All other fees		8		6

(a) 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.

(b) Tax fees consist of the aggregate fees billed for professional services rendered by PricewaterhouseCoopers LLP for tax compliance, tax advice, and tax planning.

PECO

	Year Ended December 31,
(in thousands)	2005		2004
Audit fees	$	1,265	$	1,275
Audit related fees (a)		31		28
Tax fees (b)		25		526
All other fees		4		4

(a) Audit related fees consist of assurance and related services that are reasonably related to the performance of the audit or review of PECO’s financial statements. This category includes fees for regulatory work, depreciation studies and internal control projects.

(b) Tax fees consist of the aggregate fees billed for professional services rendered by PricewaterhouseCoopers LLP for tax compliance, tax advice, tax planning and tax advice and consulting services in connection with appeals claims.

Generation

	Year Ended December 31,
(in thousands)	2005		2004
Audit fees	$	2,723	$	2,566
Audit related fees (a)		—		84
Tax fees (b)		109		38
All other fees		10		7

(a) 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.

(b) Tax fees consist of the aggregate fees billed for professional services rendered by PricewaterhouseCoopers LLP for tax compliance, tax advice, and tax planning.

471

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)	FinancialStatements and Financial Statement Schedules
(1)	Exelon
(i)	FinancialStatements
	Consolidated Statements of Income for the years 2005, 2004 and 2003
	Consolidated Statements of Cash Flows for the years 2005, 2004 and 2003
	Consolidated Balance Sheets as of December 31, 2005 and 2004
	Consolidated Statements of Changes in Shareholders’ Equity for the years 2005, 2004 and 2003
	Consolidated Statements of Comprehensive Income for the years 2005, 2004 and 2003
	Notes to Consolidated Financial Statements
(ii)	FinancialStatement Schedule

472

EXELON CORPORATION AND SUBSIDIARY COMPANIES

Schedule II – Valuation and Qualifying Accounts

(in millions)

Column A	Column B		Column C						Column D			Column E
			Additions and adjustments
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, 2005
Allowance for uncollectible accounts	$	93	$	70		$	20		$	106	(a)	$	77
Reserve for obsolete materials	$	28	$	(2	)	$	—		$	—		$	26
For The Year Ended December 31, 2004
Allowance for uncollectible accounts	$	110	$	86		$	3		$	106	(a)	$	93
Reserve for obsolete materials	$	18	$	17		$	1		$	8		$	28
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

(a) Write-off of individual accounts receivable.

473

(2)	ComEd
(i)	FinancialStatements
		Consolidated Statements of Income for the years 2005, 2004 and 2003
		Consolidated Statements of Cash Flows for the years 2005, 2004 and 2003
		Consolidated Balance Sheets as of December 31, 2005 and 2004
		Consolidated Statements of Changes in Shareholders’ Equity for the years 2005, 2004 and 2003
		Consolidated Statements of Comprehensive Income for the years 2005, 2004 and 2003
		Notes to Consolidated Financial Statements
(ii)	Financial Statement Schedule

474

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

Schedule II – Valuation and Qualifying Accounts

(in millions)

Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
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, 2005
Allowance for uncollectible accounts	$	16	$	24		$	18	$	38	(a)	$	20
Reserve for obsolete materials	$	3	$	(1	)	$	—	$	—		$	2
For The Year Ended December 31, 2004
Allowance for uncollectible accounts	$	16	$	37		$	—	$	37	(a)	$	16
Reserve for obsolete materials	$	8	$	(1	)	$	1	$	5		$	3
For The Year Ended December 31, 2003
Allowance for uncollectible accounts	$	24	$	46		$	—	$	54	(a)	$	16
Reserve for obsolete materials	$	5	$	4		$	—	$	1		$	8

(a) Write-off of individual accounts receivable.

475

(3)	PECO
(i)	Financial Statements
		Consolidated Statements of Income for the years 2005, 2004 and 2003
		Consolidated Statements of Cash Flows for the years 2005, 2004 and 2003
		Consolidated Balance Sheets as of December 31, 2005 and 2004
		Consolidated Statements of Changes in Shareholders’ Equity for the years 2005, 2004 and 2003
		Consolidated Statements of Comprehensive Income for the years 2005, 2004 and 2003
		Notes to Consolidated Financial Statements
(ii)	Financial Statement Schedule

476

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

Schedule II – Valuation and Qualifying Accounts

(in millions)

Column A	Column B		Column C				Column D			Column E
			Additions and adjustments
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, 2005
Allowance for uncollectible accounts	$	52	$	47	$	2	$	62	(a)	$	39
Reserve for obsolete materials	$	1	$	—	$	—	$	—		$	1
For The Year Ended December 31, 2004
Allowance for uncollectible accounts	$	72	$	46	$	2	$	68	(a)	$	52
Reserve for obsolete materials	$	—	$	1	$	—	$	—		$	1
For The Year Ended December 31, 2003
Allowance for uncollectible accounts	$	72	$	52	$	8	$	60	(a)	$	72

(a) Write-off of individual accounts receivable.

477

(4)	Generation
(i)	Financial Statements
		Consolidated Statements of Income for the years 2005, 2004 and 2003
		Consolidated Statements of Cash Flows for the years 2005, 2004 and 2003
		Consolidated Balance Sheets as of December 31, 2005 and 2004
		Consolidated Statements of Changes in Member’s Equity for the years 2005, 2004 and 2003
		Consolidated Statements of Comprehensive Income for the years 2005, 2004 and 2003
		Notes to Consolidated Financial Statements
(ii)	Financial Statement Schedule

478

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
			Additions and adjustments
	Balance at Beginning of Year		Charged to Cost and Expenses			Charged to Other Accounts			Deductions			Balance at End of Year
Description
For The Year Ended December 31, 2005
Allowance for uncollectible accounts	$	19	$	—		$	(2	)	$	(2	)	$	15
Reserve for obsolete materials	$	24	$	(1	)	$	—		$	—		$	23
For The Year Ended December 31, 2004
Allowance for uncollectible accounts	$	14	$	2		$	4		$	1		$	19
Reserve for obsolete materials	$	9	$	18		$	—		$	3		$	24
For The Year Ended December 31, 2003
Allowance for uncollectible accounts	$	22	$	1		$	(9	)	$	—		$	14
Reserve for obsolete materials	$	13	$	1		$	—		$	5		$	9

479

(b) 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. 0-16844, PECO Energy Company Form 10-Q for the quarter ended September 30, 2000, Exhibit 2-1).
2-2	Agreement and Plan of Merger between Exelon Corporation and Public Service Enterprise Group Incorporated dated as of December 20, 2004 (File No. 1-16169, Form 8-K dated December 21, 2004, Exhibit 2.1).
3-1	Articles of Incorporation of Exelon Corporation (Registration Statement No. 333-37082, Form S-4, Exhibit 3-1).
3-2	Amendment to Articles of Incorporation of Exelon Corporation (File No. 1-16169, Form 10-Q for the quarter ended June 30, 2004, Exhibit 3-1).
3-3	Amended and Restated Bylaws of Exelon Corporation, adopted January 27, 2004 (File No. 1-16169, 2003 Form 10-K Exhibit 3-2).
3-4	Amended and Restated Articles of Incorporation of PECO Energy Company (File No. 1-01401, 2000 Form 10-K, Exhibit 3-3).
3-5	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).
3-6	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).
3-7	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).
3-8	Certificate of Formation of Exelon Generation Company, LLC (Registration Statement No. 333-85496, Form S-4, Exhibit 3-1).
3-9	First Amended and Restated Operating Agreement of Exelon Generation Company, LLC executed as of January 1, 2001 (File No. 333-85496, 2003 Form 10-K, Exhibit 3-8).
3-10	Amendment to Articles of Incorporation of Exelon Corporation (File No. 1-16169, Form 10-Q for the quarter ended September 30, 2005, Exhibit 3-10).
3-11	Amended and Restated By-Laws of Commonwealth Edison Company (File No. 1-16169, Exelon Corporation Form 8-K filed January 27, 2006, Exhibit 99.1).
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 (Wachovia Bank, National Association), (Registration No. 2-2281, Exhibit B-1).

480

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
	April 15, 2004	0-16844, September 30, 2004 Form 10-Q	4-1-1
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).
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

481

Dated as of	File Reference	Exhibit No.
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 May 20, 2002 June 1, 2002 October 7, 2002	1-1839, 2001 Form 10-K	4-4-1
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
February 15, 2005	1-16169, Form 10-Q for the quarter ended March 31, 2005	4-3-1

482

Exhibit No.	Description
4-3-2	Instrument of Resignation, Appointment and Acceptance dated as of February 20, 2002, under the provisions of the Mortgage of Commonwealth Edison Company 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 of Commonwealth Edison Company 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 (File No. 333-85496, 2003 Form 10-K, Exhibit 4-6).
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).
4-10	Indenture dated May 1, 2001 between Exelon and J.P. Morgan Trust Company, National Association (formerly known as Chase Manhattan Trust Company, National Association), as trustee (File No. 1-16169, Exelon Corporation Form 10-Q for the quarter ended June 30, 2005, Exhibit 4-10).
4-11	Form of $400,000,000 4.45% senior notes due 2010 dated June 9, 2005 issued by Exelon Corporation (File No. 1-16169, Exelon Corporation Form 8-K dated June 9, 2005, Exhibit 99.1).
4-12	Form of $800,000,000 4.90% senior notes due 2015 dated June 9, 2005 issued by Exelon Corporation (File No. 1-16169, Exelon Corporation Form 8-K dated June 9, 2005, Exhibit 99.2).
4-13	Form of $500,000,000 5.625% senior notes due 2035 dated June 9, 2005 issued by Exelon Corporation (File No. 1-16169, Exelon Corporation Form 8-K dated June 9, 2005, Exhibit 99.3).

483

Exhibit No.	Description
10-2	Power Purchase Agreement among Generation and PECO (Registration Statement No. 333-85496, Form S-4, Exhibit 10.1).
10-3	Amended and Restated Power Purchase Agreement between Exelon Generation Company, LLC and Commonwealth Edison Company as of April 30, 2004 (File Nos. 1-01839 and 333-85496, Form 10-Q for quarter ended June 30, 2004, Exhibit 10-1).
10-6	Exelon Corporation Deferred Compensation Plan (File No. 1-16169, 2001 Form 10-K, Exhibit 10-3).
10-7	Exelon Corporation Retirement Program (File No. 1-16169, 2001 Form 10-K, Exhibit 10-4).
10-8	PECO Energy Company Unfunded Deferred Compensation Plan for Directors* (Registration Statement No. 333-49780, Form S-8, Exhibit 4-4).
10-9	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).
10-10-1	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).
10-10-2	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).
10-10-3	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).
10-11	PECO Energy Company Management Incentive Compensation Plan *(File No. 1-01401, 1997 Proxy Statement, Appendix A).
10-12	PECO Energy Company 1998 Stock Option Plan* (Registration Statement No. 333-37082, Post-Effective Amendment No. 1 to Form S-4, Exhibit 4-3).
10-13	Exelon Corporation Employee Savings Plan (File No. 1-16169, 2004 Form 10-K, Exhibit 10-13).
10-14	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).
10-15	Indenture dated as of March 1, 1999 between PECO Energy Transition Trust and The Bank of New York. (File No. 1-01401, PECO Energy Transition Trust Report on Form 8-K dated March 25, 1999, Exhibit 4.3.1).
10-15-1	Series Supplement dated as of March 25, 1999 between PECO Energy Transition Trust and The Bank of New York. (File No. 1-01401, PECO Energy Transition Trust Report on Form 8-K dated March 25, 1999, Exhibit 4.3.2).
10-15-2	Series Supplement dated as of March 1, 2001 between PECO Energy Transition Trust and The Bank of New York. (File No. 1-01401, PECO Energy Transition Trust Report on Form 8-K dated March 1, 2001, Exhibit 4.3.2).

484

Exhibit No.	Description
10-15-3	Series Supplement dated as of May 2, 2000 between PECO Energy Transition Trust and The Bank of New York (File No. 1-01401, PECO Energy Transition Trust Report on Form 8-K dated May 2, 2000, Exhibit 4.3.2).
10-16	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. 1-01401, PECO Energy Transition Trust Report on Form 8-K dated May 2, 2000, Exhibit 10.1).
10-16-1	Amendment No. 1 to Intangible Transition Property Sale Agreement dated as of March 25, 1999, as amended and restated as of May 2, 2000 (File No. 1-01401, PECO Energy Company and PECO Energy Transition Trust Report on Form 8-K dated March 1, 2001).
10-17	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. 1-01401, PECO Energy Transition Trust Current Report on Form 8-K dated May 2, 2000, Exhibit 10.2).
10-17-1	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).
10-18	Exelon Corporation Cash Balance Pension Plan (File No. 1-16169, 2001 Form 10-K, Exhibit 10-14).
10-19	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).
10-20	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).
10-21	Unicom Corporation Amended and Restated Long-Term Incentive Plan *(File No. 1-11375, Unicom Proxy Statement dated April 7, 1999, Exhibit A).
10-21-1	First Amendment to Unicom Corporation Amended and Restated Long Term Incentive Plan *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-8).
10-21-2	Second Amendment to Unicom Corporation Amended and Restated Long Term Incentive Plan *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-9).
10-22	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).
10-23	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).
10-24	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).
10-25	Unicom Corporation Deferred Compensation Unit Plan, as amended *(File Nos. 1-11375 and 1-1839, 1995 Form 10-K, Exhibit 10-12).

485

Exhibit No.	Description
10-26	Exelon Corporation Corporate Stock Deferral Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-22).
10-27	Unicom Corporation Retirement Plan for Directors, as amended *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-12).
10-28	Commonwealth Edison Company Retirement Plan for Directors, as amended *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-13).
10-29	Unicom Corporation 1996 Directors’ Fee Plan *(File No. 1-11375, Unicom Proxy Statement dated April 8, 1996, Appendix A).
10-29-1	Second Amendment to Unicom Corporation 1996 Directors Fee Plan *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-11).
10-31	Commonwealth Edison Company Executive Group Life Insurance Plan* (File No. 1-1839, 1980 Form 10-K, Exhibit 10-3).
10-31-1	Amendment to the Commonwealth Edison Company Executive Group Life Insurance Plan *(File No. 1-1839, 1981 Form 10-K, Exhibit 10-4).
10-31-2	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).
10-31-3	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).
10-31-4	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).
10-32	Not used.
10-32-1	First Amendment to the Commonwealth Edison Company Supplemental Management Retirement Plan. * (File No. 1-1839, 2000 Form 10-K, Exhibit 10-27-1)
10-35	Amendment No. 1 to Exelon Corporation Supplemental Management Retirement Plan* (File No. 1-16169, 2001 Form 10-K, Exhibit 10-32).
10-36	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	PECO Energy Company Supplemental Pension Benefit Plan (As Amended and Restated January 1, 2001)* (File No. 0-16844, 2001 Form 10-K, Exhibit 10-35).
10-40	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).
10-40-1	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).

486

Exhibit No.	Description
10-43	$1,000,000,000 Five Year Credit Agreement dated as of July 16, 2004 among Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC as Borrowers and Various Financial Institutions as Lenders (File No. 1-16169, Form 10-Q for quarter ended June 30, 2004, Exhibit 10-2).
10-43-1	$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 (File No. 1-16169, 2003 Form 10-K, Exhibit 10-44-1).
10-43-2	First Amendment dated as of July 16, 2004 to Three Year Credit Agreement dated as of October 31, 2003 among Exelon Corporation, Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company, LLC, various financial institutions and Bank One, NA, as administrative agent (File No. 1-16169, Form 10-Q for quarter ended June 30, 2004, Exhibit 10-3).
10-44	$850,000,000 Credit Agreement dated as of September 29, 2003 among Exelon Generation Company, LLC as Borrower and Various Financial Institutions as Lenders (File No. 333-85496, 2003 Form 10-K, Exhibit 10-45).
10-49	Exelon Corporation Annual Incentive Plan for Senior Executives effective January 1, 2004*. (File No. 1-16169, 2004 10-K, Exhibit 10-49).
10-50	Form of change in control employment agreement for senior executives newly eligible or promoted after January 1, 2004*. (File No. 1-16169, 2004 10-K, Exhibit 10-50).
10-51	Form of change in control employment agreement *(amended and restated as of May 1, 2004). (File No. 1-16169, 2004 10-K, Exhibit 10-51).
10-52	Amendment One to Exelon Corporation Deferred Compensation Plan*. (File No. 1-16169, 2004 10-K, Exhibit 10-52).
10-53	Amendment Two to Exelon Corporation Supplemental Management Retirement Plan*. (File No. 1-16169, 2004 10-K, Exhibit 10-53).
10-54	Restatement of the Exelon Corporation Employee Stock Purchase Plan, effective May 1, 2004 and Appendix One thereto. (File No. 1-16169, 2004 10-K, Exhibit 10-54).
10-55	$500 million term loan agreement dated April 1, 2005 among Exelon Corporation, lenders named within the agreement and Dresdner Bank AG, New York and Grand Cayman Branches, as Administrative Agent (File No. 1-16169, Exelon Corporation Form 8-K dated April 1, 2005, Exhibit 99).
10-56	Amended and Restated Employment Agreement by and between Exelon Corporation and John W. Rowe, dated as of July 22, 2005 *(File No. 1-16169, Exelon Corporation Form 10-Q for the quarter ended June 30, 2005, Exhibit 10-2).
10-57	Exelon Corporation 2006 Long-Term Incentive Plan (Registration Statement No. 333-122704, Joint Proxy Statement-Prospectus pursuant to Rule 424(b)(3) filed June 3, 2005, Annex H).
10-58	Form of Stock Option Grant Instrument under the Exelon Corporation 2006 Long-Term Incentive Plan (File No. 1-16169, Form 8-K filed January 27, 2006, Exhibit 99.2).
10-59	Exelon Corporation Employee Stock Purchase Plan for Unincorporated Subsidiaries (Registration Statement No. 333-122704, Joint Proxy Statement-Prospectus pursuant to Rule 424(b)(3) filed June 3, 2005, Annex I).

487

Exhibit No.	Description
10-60	$300 million term loan agreement dated April 1, 2005 among Exelon Corporation, lenders named within the agreement, and Dresdner Bank AG, New York and Grand Cayman Branches, as Administrative Agent.
10-61	First Amendment dated as of November 30, 2005 to $300 million term loan agreement dated April 1, 2005 among Exelon Corporation, lenders named within the agreement, and Dresdner Bank AG, New York and Grand Cayman Branches, as Administrative Agent.
10-62	Exelon Corporation Senior Management Severance Plan (As Amended and Restated).
10-63	Form of Separation Agreement under Exelon Corporation Senior Management Severance Plan (As Amended and Restated).
14	Exelon Code of Conduct (File No. 1-16169, 2004 10-K, Exhibit 14).
	Subsidiaries
21-1	Exelon Corporation
21-2	Commonwealth Edison Company
21-3	PECO Energy Company
21-4	Exelon Generation Company, LLC
	Consent of Independent Auditors
23-1	Exelon Corporation
23-2	Commonwealth Edison Company
23-3	PECO Energy Company

488

Exhibit No.	Description
	Power of Attorney (Exelon Corporation)
24-1	Edward A. Brennan
24-2	M. Walter D’Alessio
24-3	Nicholas DeBenedictis
24-4	Bruce DeMars
24-5	Nelson A. Diaz
24-6	Sue L. Gin
24-7	Rosemarie B. Greco
24-8	Edgar D. Jannotta
24-9	John M. Palms, Ph.D.
24-10	William C. Richardson
24-11	Thomas J. Ridge
24-12	John W. Rogers, Jr.
24-13	Ronald Rubin
24-14	Richard L. Thomas
	Power of Attorney (Commonwealth Edison Company)
24-15	Sue L. Gin
24-16	Edgar D. Jannotta
24-17	John W. Rogers, Jr.
24-18	Richard L. Thomas
	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, 2005 filed by the following officers for the following registrants:
31-1	Filed by John W. Rowe for Exelon Corporation
31-2	Filed by John F. Young for Exelon Corporation
31-3	Filed by Frank M. Clark for Commonwealth Edison Company
31-4	Filed by Robert K. McDonald for Commonwealth Edison Company
31-5	Filed by John L. Skolds for PECO Energy Company
31-6	Filed by John F. Young for PECO Energy Company
31-7	Filed by John L. Skolds for Exelon Generation Company, LLC
31-8	Filed by John F. Young for Exelon Generation Company, LLC

489

Exhibit No.	Description
	Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code as to the Annual Report on Form 10-K for the year ended December 31, 2005 filed by the following officers for the following registrants:
32-1	Filed by John W. Rowe for Exelon Corporation
32-2	Filed by John F. Young for Exelon Corporation
32-3	Filed by Frank M. Clark for Commonwealth Edison Company
32-4	Filed by Robert K. McDonald for Commonwealth Edison Company
32-5	Filed by John L. Skolds for PECO Energy Company
32-6	Filed by John F. Young for PECO Energy Company
32-7	Filed by John L. Skolds for Exelon Generation Company, LLC
32-8	Filed by John F. Young 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.

490

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 15th day of February, 2006.

EXELON CORPORATION
By:	/s/    JOHN W. ROWE
Name:	John W. Rowe
Title:	Chairman, Chief Executive Officer and President

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 15th day of February, 2006.

Signature	Title
/s/    JOHN W. ROWE         John W. Rowe	Chairman, Chief Executive Officer and President (Principal Executive Officer)
/s/    JOHN F. YOUNG         John F. Young	Executive Vice President, Finance and Markets and Chief Financial Officer (Principal Financial Officer)
/s/    MATTHEW F. HILZINGER         Matthew F. Hilzinger	Senior 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	Edgar D. Jannotta
M. Walter D’Alessio	John M. Palms, PhD.
Nicholas Debenedictis	William C. Richarson
Bruce DeMars	Thomas J. Ridge
Nelson A. Diaz	John W. Rogers, Jr.
Sue L. Gin	Ronald Rubin
Rosemarie B. Greco	Richard L. Thomas

By:	/s/    JOHN W. ROWE	February 15, 2006
Name:	John W. Rowe

491

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 15th day of February, 2006.

COMMONWEALTH EDISON COMPANY
By:	/s/    FRANK M. CLARK
Name:	Frank M. Clark
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 15th day of February, 2006.

Signature	Title
/s/    FRANK M. CLARK         Frank M. Clark	Chairman and Chief Executive Officer (Principal Executive Officer)
/s/    J. Barry Mitchell         J. Barry Mitchell	President
/s/    Robert K. McDonald         Robert K. McDonald	Senior Vice President, Chief Financial Officer, Treasurer and Chief Risk Officer (Principal Financial Officer)
/s/    Matthew F. Hilzinger         Matthew F. Hilzinger	Senior Vice President and Corporate Controller, Exelon (Principal Accounting Officer)

This annual report has also been signed below by Frank M. Clark, Attorney-in-Fact, on behalf of the following Directors on the date indicated:

Sue L. Gin	John W. Rogers, Jr.
Edgar D. Jannotta	Richard L .Thomas

By:	/s/    FRANK M. CLARK	February 15, 2006
Name:	Frank M. Clark

492

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 15th day of February, 2006.

PECO ENERGY COMPANY
By:	/s/    JOHN W. ROWE
Name:	John W. Rowe
Title:	Chairman, Chief Executive Officer and President, Exelon, and Director

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 15th day of February, 2006.

Signature	Title
/s/    JOHN W. ROWE         John W. Rowe	Chairman, Chief Executive Officer and President, Exelon, and Director
/s/    JOHN L. SKOLDS          John L. Skolds	President, Exelon Energy Delivery, and Director (Principal Executive Officer)
/s/    JOHN F. YOUNG         John F. Young	Executive Vice President, Finance and Markets and Chief Financial Officer, Exelon, and Chief Financial Officer (Principal Financial Officer)
/s/    DENIS P. O’BRIEN         Denis P. O’Brien	President and Director
/s/    MATTHEW F. HILZINGER         Matthew F. Hilzinger	Senior Vice President and Corporate Controller, Exelon (Principal Accounting Officer)

493

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 15th day of February, 2006.

EXELON GENERATION COMPANY, LLC
By:	/s/    JOHN W. ROWE
Name:	John W. Rowe
Title:	Chairman, Chief Executive Officer and President, Exelon

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 15th day of February, 2006.

Signature	Title
/s/    JOHN W. ROWE         John W. Rowe	Chairman, Chief Executive Officer and President, Exelon
/s/    JOHN L. SKOLDS         John L. Skolds	President (Principal Executive Officer)
/s/    JOHN F. YOUNG         John F. Young	Executive Vice President, Finance and Markets and Chief Financial Officer, Exelon, and Chief Financial Officer (Principal Financial Officer)
/s/    JON D. VEURINK         Jon D. Veurink	Vice President and Controller (Principal Accounting Officer)

494